UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
ý | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the quarterly period ended December 31, 2018
OR
¨ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from ________ to ________
Commission file number 1-11071
UGI CORPORATION
(Exact name of registrant as specified in its charter)
Pennsylvania | 23-2668356 | |
(State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification No.) | |
460 North Gulph Road, King of Prussia, PA | 19406 | |
(Address of principal executive offices) | (Zip Code) | |
(610) 337-1000
(Registrant’s telephone number, including area code)
______________________________________
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý No ¨
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ý No ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer | ý | Accelerated filer | ¨ | Non-accelerated filer | ¨ | ||
Smaller reporting company | ¨ | Emerging growth company | ¨ | ||||
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No ý
At January 31, 2019, there were 173,844,100 shares of UGI Corporation Common Stock, without par value, outstanding.
UGI CORPORATION AND SUBSIDIARIES
TABLE OF CONTENTS
Page | |
i
GLOSSARY OF TERMS AND ABBREVIATIONS
Terms and abbreviations used in this Form 10-Q are defined below:
UGI Corporation and Related Entities
AmeriGas OLP - AmeriGas Propane, L.P., the principal operating subsidiary of AmeriGas Partners
AmeriGas Partners - AmeriGas Partners, L.P., a publicly traded limited partnership. AmeriGas Partners, L.P. is also referred to as the “Partnership”
AmeriGas Propane - Reportable segment comprising AmeriGas Propane, Inc. and its subsidiaries, including AmeriGas Partners and AmeriGas OLP
AmeriGas Propane, Inc. - A wholly owned subsidiary of UGI and the general partner of AmeriGas Partners and AmeriGas OLP. Also referred to as the General Partner
AvantiGas - AvantiGas Limited, a wholly owned subsidiary of UGI International, LLC
Company - UGI and its consolidated subsidiaries collectively
CPG - UGI Central Penn Gas, Inc., a wholly owned subsidiary of UGI Utilities prior to October 1, 2018
DVEP - DVEP Investeringen B.V., a wholly owned subsidiary of UGI International, LLC
Electric Utility - UGI Utilities’ regulated electric distribution utility
Energy Services - UGI Energy Services, LLC, a wholly owned subsidiary of Enterprises
Enterprises - UGI Enterprises, LLC, a wholly owned subsidiary of UGI
ESFC - Energy Services Funding Corporation, a wholly owned subsidiary of Energy Services
Finagaz - The retail LPG distribution business of Totalgaz SAS acquired on May 29, 2015
Flaga - Flaga GmbH, a wholly owned subsidiary of UGI International, LLC
Gas Utility - UGI Utilities’ regulated natural gas distribution businesses, comprising the natural gas utility businesses owned and operated by UGI Utilities and, prior to the Utility Merger, PNG and CPG
General Partner - AmeriGas Propane, Inc., the general partner of AmeriGas Partners and AmeriGas OLP
HVAC - UGI HVAC Enterprises, Inc., a wholly owned subsidiary of Enterprises
Midstream & Marketing - Reportable segment comprising Energy Services, UGID and HVAC
Partnership - AmeriGas Partners and its consolidated subsidiaries, including AmeriGas OLP
PennEast - PennEast Pipeline Company, LLC
PNG - UGI Penn Natural Gas, Inc., a wholly owned subsidiary of UGI Utilities prior to October 1, 2018
UGI - UGI Corporation
UGI Central - The natural gas rate district of CPG subsequent to the Utility Merger
UGI France - UGI France SAS (a Société par actions simplifiée), a wholly owned subsidiary of UGI International, LLC
UGI Gas - UGI Utilities’ natural gas utility prior to the Utility Merger
UGI International - Reportable segment comprising UGI’s foreign operations
UGI International, LLC - UGI International, LLC, a wholly owned subsidiary of Enterprises
1
UGI North - The natural gas rate district of PNG subsequent to the Utility Merger
UGI PennEast, LLC - A wholly owned subsidiary of Energy Services that holds a 20% membership interest in PennEast
UGI South - The natural gas rate district of UGI Gas subsequent to the Utility Merger
UGI Utilities - UGI Utilities, Inc., a wholly owned subsidiary of UGI. Also a reportable segment of UGI
UGID - UGI Development Company, a wholly owned subsidiary of Energy Services
UniverGas - UniverGas Italia S.r.l, a wholly owned subsidiary of UGI International
Other Terms and Abbreviations
2017 three-month period - Three-month period ended December 31, 2017
2018 Annual Report - UGI Annual Report on Form 10-K for the fiscal year ended September 30, 2018
2018 three-month period - Three-month period ended December 31, 2018
2018 UGI International Credit Facilities Agreement - A five-year unsecured Senior Facilities Agreement entered into by UGI International, LLC comprising a €300 million term loan facility and a €300 million revolving credit facility maturing October 2023
AFUDC - Allowance for funds used during construction
AOCI - Accumulated other comprehensive income (loss)
ASC - Accounting Standards Codification
ASC 605 - ASC 605, “Revenue Recognition”
ASC 606 - ASC 606, “Revenue from Contracts with Customers”
ASC 740 - ASC 740, “Income Taxes”
ASU - Accounting Standards Update
Bcf - Billions of cubic feet
BIE - Pennsylvania Public Utility Commission Bureau of Investigation and Enforcement
BRP - Balance Responsible Party providing electricity imbalance services in the European electricity markets
COA - Consent order and agreement
CODM - Chief Operating Decision Maker as defined in ASC 280, “Segment Reporting”
Common Units - Limited partnership ownership interests in AmeriGas Partners
Core market - Comprises (1) firm residential, commercial and industrial customers for whom UGI Utilities has a statutory obligation to serve who purchase their natural gas or electricity from UGI Utilities; and (2) residential, commercial and industrial customers for whom UGI Utilities has a statutory obligation to serve who purchase their natural gas or electricity from others
December 2017 French Finance Bills - The French Finance Bill for 2018 and the second amendment to the French Finance Bill for 2017
DS - Default service
Exchange Act - Securities Exchange Act of 1934, as amended
FASB - Financial Accounting Standards Board
2
FDIC - Federal Deposit Insurance Corporation
FERC - Federal Energy Regulatory Commission
FTR - Financial transmission rights
GAAP - U.S. generally accepted accounting principles
Gwh - Millions of kilowatt hours
ICE - Intercontinental Exchange
IRPA - Interest rate protection agreement
IT - Information technology
LIBOR - London Inter-bank Offered Rate
LNG - Liquefied natural gas
LPG - Liquefied petroleum gases
MDPSC - Maryland Public Service Commission
MGP - Manufactured gas plant
NOAA - National Oceanic and Atmospheric Administration
NPNS - Normal purchase and normal sale
NYDEC - New York State Department of Environmental Conservation
NYISO - New York Independent System Operator
NYMEX - New York Mercantile Exchange
PADEP - Pennsylvania Department of Environmental Protection
PAPUC - Pennsylvania Public Utility Commission
Partnership Adjusted EBITDA - A non-GAAP financial measure used by UGI to evaluate the Partnership’s performance consisting of Partnership earnings before interest expense, income taxes, depreciation and amortization as adjusted for the effects of gains and losses on commodity derivative instruments not associated with current-period transactions and other gains and losses that competitors do not necessarily have
PGC - Purchased gas costs
PJM - PJM Interconnection, LLC
PRP - Potentially responsible party
Receivables Facility - A receivables purchase facility of Energy Services with an issuer of receivables-backed commercial paper
Retail core-market - Comprises firm residential, commercial and industrial customers for whom UGI Utilities has a statutory obligation to serve that purchase their natural gas from Gas Utility
ROD - Records of Decision
SCAA - Storage contract administrative agreements
SEC - U.S. Securities and Exchange Commission
3
TCJA - Tax Cuts and Jobs Act
UGI International 3.25% Senior Notes - An underwritten private placement of €350 million principal amount of senior unsecured notes due November 1, 2025, issued by UGI International, LLC
UGI Utilities 4.55% Senior Notes - A private placement of $150 million principal amount of senior notes issued by UGI Utilities due February 2049
USD - U.S. dollar
U.S. Pension Plan - Defined benefit pension plan for employees hired prior to January 1, 2009 of UGI, UGI Utilities, CPG, PNG and certain of UGI’s other domestic wholly owned subsidiaries
Utility Merger - The merger, effective October 1, 2018, of CPG and PNG with and into UGI Utilities
VEBA - Voluntary Employees’ Beneficiary Association
Western Missouri District Court - The United States District Court for the Western District of Missouri
4
UGI CORPORATION AND SUBSIDIARIES
PART I FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
CONDENSED CONSOLIDATED BALANCE SHEETS
(unaudited)
(Millions of dollars)
December 31, 2018 | September 30, 2018 | December 31, 2017 | ||||||||||
ASSETS | ||||||||||||
Current assets: | ||||||||||||
Cash and cash equivalents | $ | 477.6 | $ | 452.6 | $ | 446.4 | ||||||
Restricted cash | 17.4 | 9.6 | 19.8 | |||||||||
Accounts receivable (less allowances for doubtful accounts of $38.5, $35.1 and $35.1, respectively) | 1,144.3 | 751.9 | 1,101.8 | |||||||||
Accrued utility revenues | 64.7 | 14.0 | 95.9 | |||||||||
Inventories | 293.7 | 318.2 | 307.3 | |||||||||
Utility regulatory assets | 3.3 | 7.5 | 0.6 | |||||||||
Derivative instruments | 60.2 | 142.5 | 73.4 | |||||||||
Prepaid expenses and other current assets | 181.0 | 191.8 | 135.4 | |||||||||
Total current assets | 2,242.2 | 1,888.1 | 2,180.6 | |||||||||
Property, plant and equipment, at cost (less accumulated depreciation of $3,228.3, $3,153.9 and $3,393.1, respectively) | 5,855.1 | 5,808.2 | 5,690.5 | |||||||||
Goodwill | 3,154.8 | 3,160.4 | 3,185.5 | |||||||||
Intangible assets, net | 505.2 | 513.6 | 641.9 | |||||||||
Utility regulatory assets | 295.5 | 293.5 | 362.2 | |||||||||
Derivative instruments | 29.9 | 43.5 | 13.3 | |||||||||
Other assets | 285.6 | 273.6 | 269.9 | |||||||||
Total assets | $ | 12,368.3 | $ | 11,980.9 | $ | 12,343.9 | ||||||
LIABILITIES AND EQUITY | ||||||||||||
Current liabilities: | ||||||||||||
Current maturities of long-term debt | $ | 19.5 | $ | 18.8 | $ | 224.1 | ||||||
Short-term borrowings | 676.3 | 424.9 | 586.1 | |||||||||
Accounts payable | 753.3 | 561.8 | 680.8 | |||||||||
Derivative instruments | 56.8 | 11.7 | 32.7 | |||||||||
Other current liabilities | 677.2 | 714.9 | 692.3 | |||||||||
Total current liabilities | 2,183.1 | 1,732.1 | 2,216.0 | |||||||||
Long-term debt | 4,150.7 | 4,146.5 | 4,056.4 | |||||||||
Deferred income taxes | 973.4 | 991.9 | 890.7 | |||||||||
Derivative instruments | 25.0 | 12.8 | 22.2 | |||||||||
Other noncurrent liabilities | 989.5 | 997.6 | 1,076.5 | |||||||||
Total liabilities | 8,321.7 | 7,880.9 | 8,261.8 | |||||||||
Commitments and contingencies (Note 11) | ||||||||||||
Equity: | ||||||||||||
UGI Corporation stockholders’ equity: | ||||||||||||
UGI Common Stock, without par value (authorized — 450,000,000 shares; issued — 174,262,763, 174,142,997 and 173,997,441 shares, respectively) | 1,206.5 | 1,200.8 | 1,189.3 | |||||||||
Retained earnings | 2,620.8 | 2,610.7 | 2,429.3 | |||||||||
Accumulated other comprehensive loss | (133.1 | ) | (110.4 | ) | (71.5 | ) | ||||||
Treasury stock, at cost | (24.8 | ) | (19.7 | ) | (45.4 | ) | ||||||
Total UGI Corporation stockholders’ equity | 3,669.4 | 3,681.4 | 3,501.7 | |||||||||
Noncontrolling interests, principally in AmeriGas Partners | 377.2 | 418.6 | 580.4 | |||||||||
Total equity | 4,046.6 | 4,100.0 | 4,082.1 | |||||||||
Total liabilities and equity | $ | 12,368.3 | $ | 11,980.9 | $ | 12,343.9 | ||||||
See accompanying notes to condensed consolidated financial statements.
5
UGI CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(unaudited)
(Millions of dollars, except per share amounts)
Three Months Ended December 31, | ||||||||
2018 | 2017 | |||||||
Revenues | $ | 2,200.2 | $ | 2,125.2 | ||||
Costs and expenses: | ||||||||
Cost of sales (excluding depreciation and amortization shown below) | 1,425.0 | 1,137.4 | ||||||
Operating and administrative expenses | 503.2 | 486.9 | ||||||
Depreciation and amortization | 111.2 | 110.3 | ||||||
Other operating income, net | (6.9 | ) | (4.4 | ) | ||||
2,032.5 | 1,730.2 | |||||||
Operating income | 167.7 | 395.0 | ||||||
Income from equity investees | 1.5 | 1.0 | ||||||
Loss on extinguishments of debt | (6.1 | ) | — | |||||
Other non-operating income (expense), net | 9.0 | (8.0 | ) | |||||
Interest expense | (60.2 | ) | (58.2 | ) | ||||
Income before income taxes | 111.9 | 329.8 | ||||||
Income tax (expense) benefit | (23.4 | ) | 104.4 | |||||
Net income including noncontrolling interests | 88.5 | 434.2 | ||||||
Deduct net income attributable to noncontrolling interests, principally in AmeriGas Partners | (24.3 | ) | (68.3 | ) | ||||
Net income attributable to UGI Corporation | $ | 64.2 | $ | 365.9 | ||||
Earnings per common share attributable to UGI Corporation stockholders: | ||||||||
Basic | $ | 0.37 | $ | 2.11 | ||||
Diluted | $ | 0.36 | $ | 2.07 | ||||
Weighted-average common shares outstanding (thousands): | ||||||||
Basic | 174,413 | 173,670 | ||||||
Diluted | 177,566 | 176,948 | ||||||
Dividends declared per common share | $ | 0.26 | $ | 0.25 | ||||
See accompanying notes to condensed consolidated financial statements.
6
UGI CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(unaudited)
(Millions of dollars)
Three Months Ended December 31, | ||||||||
2018 | 2017 | |||||||
Net income including noncontrolling interests | $ | 88.5 | $ | 434.2 | ||||
Other comprehensive income (loss): | ||||||||
Net losses on derivative instruments (net of tax of $0.4 and $0.2, respectively) | (1.5 | ) | (0.4 | ) | ||||
Reclassifications of net losses (gains) on derivative instruments (net of tax of $(0.3) and $0.1, respectively) | 0.7 | (0.4 | ) | |||||
Foreign currency adjustments (net of tax of $2.8 and $0.0, respectively) | (15.6 | ) | 22.3 | |||||
Benefit plans (net of tax of $(0.1), and $(0.2), respectively) | 0.3 | 0.4 | ||||||
Other comprehensive (loss) income | (16.1 | ) | 21.9 | |||||
Comprehensive income including noncontrolling interests | 72.4 | 456.1 | ||||||
Deduct comprehensive income attributable to noncontrolling interests, principally in AmeriGas Partners | (24.3 | ) | (68.3 | ) | ||||
Comprehensive income attributable to UGI Corporation | $ | 48.1 | $ | 387.8 | ||||
See accompanying notes to condensed consolidated financial statements.
7
UGI CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(unaudited)
(Millions of dollars)
Three Months Ended December 31, | ||||||||
2018 | 2017 | |||||||
CASH FLOWS FROM OPERATING ACTIVITIES | ||||||||
Net income including noncontrolling interests | $ | 88.5 | $ | 434.2 | ||||
Adjustments to reconcile net income including noncontrolling interest to net cash provided by operating activities: | ||||||||
Depreciation and amortization | 111.2 | 110.3 | ||||||
Deferred income tax benefit, net | (20.7 | ) | (173.9 | ) | ||||
Provision for uncollectible accounts | 10.3 | 9.3 | ||||||
Changes in unrealized gains and losses on derivative instruments | 165.9 | (6.6 | ) | |||||
Loss on extinguishments of debt | 6.1 | — | ||||||
Other, net | 10.9 | 7.6 | ||||||
Net change in: | ||||||||
Accounts receivable and accrued utility revenues | (457.6 | ) | (530.5 | ) | ||||
Inventories | 23.0 | (23.5 | ) | |||||
Utility deferred fuel and power costs, net of changes in unsettled derivatives | (12.5 | ) | 11.6 | |||||
Accounts payable | 217.4 | 235.0 | ||||||
Derivative instruments collateral deposits (paid) received | (22.2 | ) | 3.7 | |||||
Other current assets | (11.4 | ) | (34.0 | ) | ||||
Other current liabilities | (12.3 | ) | (11.8 | ) | ||||
Net cash provided by operating activities | 96.6 | 31.4 | ||||||
CASH FLOWS FROM INVESTING ACTIVITIES | ||||||||
Expenditures for property, plant and equipment | (183.3 | ) | (147.5 | ) | ||||
Acquisitions of businesses and assets, net of cash acquired | (15.0 | ) | (175.8 | ) | ||||
Other | 4.3 | 5.3 | ||||||
Net cash used by investing activities | (194.0 | ) | (318.0 | ) | ||||
CASH FLOWS FROM FINANCING ACTIVITIES | ||||||||
Dividends on UGI Common Stock | (45.3 | ) | (43.3 | ) | ||||
Distributions on AmeriGas Partners publicly held Common Units | (65.7 | ) | (65.7 | ) | ||||
Issuances of long-term debt, net of issuance costs | 728.9 | 124.3 | ||||||
Repayments of long-term debt | (721.1 | ) | (41.9 | ) | ||||
Increase in short-term borrowings | 243.4 | 212.5 | ||||||
Receivables Facility net borrowings | 8.0 | 6.0 | ||||||
Issuances of UGI Common Stock | 6.9 | 1.4 | ||||||
Repurchases of UGI Common Stock | (16.9 | ) | (9.5 | ) | ||||
Other | (4.2 | ) | (2.7 | ) | ||||
Net cash provided by financing activities | 134.0 | 181.1 | ||||||
EFFECT OF EXCHANGE RATE CHANGES ON CASH | (3.8 | ) | 3.0 | |||||
Cash, cash equivalents and restricted cash increase (decrease) | $ | 32.8 | $ | (102.5 | ) | |||
CASH, CASH EQUIVALENTS AND RESTRICTED CASH | ||||||||
Cash, cash equivalents and restricted cash at end of period | $ | 495.0 | $ | 466.2 | ||||
Cash, cash equivalents and restricted cash at beginning of period | 462.2 | 568.7 | ||||||
Cash, cash equivalents and restricted cash increase (decrease) | $ | 32.8 | $ | (102.5 | ) | |||
See accompanying notes to condensed consolidated financial statements.
8
UGI CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
(unaudited)
(Millions of dollars, except per share amounts)
Three Months Ended December 31, | |||||||
2018 | 2017 | ||||||
Common stock, without par value | |||||||
Balance, beginning of period | $ | 1,200.8 | $ | 1,188.6 | |||
Common Stock issued in connection with employee and director plans (including losses on treasury stock transactions), net of tax withheld | 3.7 | (1.3 | ) | ||||
Equity-based compensation expense | 2.0 | 2.0 | |||||
Balance, end of period | $ | 1,206.5 | $ | 1,189.3 | |||
Retained earnings | |||||||
Balance, beginning of period | $ | 2,610.7 | $ | 2,106.7 | |||
Cumulative effect of change in accounting principle - ASC 606 | (7.1 | ) | — | ||||
Reclassification of stranded income tax effects related to TCJA | 6.6 | — | |||||
Losses on treasury stock transactions in connection with employee and director plans | (8.3 | ) | — | ||||
Net income attributable to UGI | 64.2 | 365.9 | |||||
Cash dividends on Common Stock ($0.26 and $0.25 per share, respectively) | (45.3 | ) | (43.3 | ) | |||
Balance, end of period | $ | 2,620.8 | $ | 2,429.3 | |||
Accumulated other comprehensive income (loss) | |||||||
Balance, beginning of period | $ | (110.4 | ) | $ | (93.4 | ) | |
Reclassification of stranded income tax effects related to TCJA | (6.6 | ) | — | ||||
Net losses on derivative instruments | (1.5 | ) | (0.4 | ) | |||
Reclassification of net losses (gains) on derivative instruments | 0.7 | (0.4 | ) | ||||
Benefit plans | 0.3 | 0.4 | |||||
Foreign currency adjustments | (15.6 | ) | 22.3 | ||||
Balance, end of period | $ | (133.1 | ) | $ | (71.5 | ) | |
Treasury stock | |||||||
Balance, beginning of period | $ | (19.7 | ) | $ | (38.6 | ) | |
Common Stock issued in connection with employee and director plans, net of tax withheld | 12.2 | 2.7 | |||||
Repurchases of Common Stock | (16.9 | ) | (9.5 | ) | |||
Reacquired Common Stock — employee and director plans | (0.4 | ) | — | ||||
Balance, end of period | $ | (24.8 | ) | $ | (45.4 | ) | |
Total UGI stockholders’ equity | $ | 3,669.4 | $ | 3,501.7 | |||
Noncontrolling interests | |||||||
Balance, beginning of period | $ | 418.6 | $ | 577.6 | |||
Net income attributable to noncontrolling interests, principally in AmeriGas Partners | 24.3 | 68.3 | |||||
Dividends and distributions | (65.7 | ) | (65.7 | ) | |||
Other | — | 0.2 | |||||
Balance, end of period | $ | 377.2 | $ | 580.4 | |||
Total equity | $ | 4,046.6 | $ | 4,082.1 | |||
See accompanying notes to condensed consolidated financial statements.
9
UGI CORPORATION AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Currency in millions, except per share amounts and where indicated otherwise)
Note 1 — Nature of Operations
UGI is a holding company that, through subsidiaries and affiliates, distributes, stores, transports and markets energy products and related services. In the United States, we (1) are the general partner and own limited partner interests in a retail propane marketing and distribution business; (2) own and operate natural gas and electric distribution utilities; and (3) own and operate an energy marketing, midstream infrastructure, storage, natural gas gathering, natural gas production, electricity generation and energy services business. In Europe, we market and distribute propane and other LPG and market energy products and services.
We conduct a domestic propane marketing and distribution business through AmeriGas Partners. AmeriGas Partners is a publicly traded limited partnership that conducts a national propane distribution business through its principal operating subsidiary, AmeriGas OLP. AmeriGas Partners and AmeriGas OLP are Delaware limited partnerships. UGI’s wholly owned second-tier subsidiary, AmeriGas Propane, Inc., serves as the General Partner of AmeriGas Partners and AmeriGas OLP. At December 31, 2018, the General Partner held a 1% general partner interest and a 25.3% limited partner interest in AmeriGas Partners and held an effective 27.0% ownership interest in AmeriGas OLP. Our limited partnership interest in AmeriGas Partners comprises Common Units. The remaining 73.7% interest in AmeriGas Partners comprises Common Units held by the public. The General Partner also holds incentive distribution rights that entitle it to receive distributions from AmeriGas Partners in excess of its 1% general partner interest under certain circumstances as further described in Note 14 of the Company’s 2018 Annual Report. Incentive distributions received by the General Partner during the three months ended December 31, 2018 and 2017 were $11.3 each.
Our wholly owned subsidiary, Enterprises, through subsidiaries, conducts (1) an LPG distribution business throughout much of Europe and (2) an energy marketing business in France, Belgium, the Netherlands and the United Kingdom. These businesses are conducted principally through our subsidiaries, UGI France, Flaga, AvantiGas, DVEP and UniverGas.
Energy Services conducts directly and through subsidiaries energy marketing, midstream transmission, LNG, storage, natural gas gathering, natural gas production, electricity generation and energy services businesses primarily in the Mid-Atlantic region of the U.S. UGID owns all or a portion of electricity generation facilities principally located in Pennsylvania. HVAC, a first-tier subsidiary of Enterprises, also conducts heating, ventilation, air-conditioning, refrigeration and electrical contracting businesses in portions of eastern and central Pennsylvania. Energy Services and its subsidiaries’ storage, LNG and portions of its midstream transmission operations are subject to regulation by the FERC.
UGI Utilities owns and operates Gas Utility, a natural gas distribution utility business in eastern and central Pennsylvania and in a portion of one Maryland county directly and, prior to the Utility Merger on October 1, 2018, through PNG and CPG. Gas Utility is subject to regulation by the PAPUC and the FERC and, with respect to a small service territory in one Maryland county, the MDPSC. UGI Utilities also owns and operates Electric Utility, an electric distribution utility located in northeastern Pennsylvania. Electric Utility is subject to regulation by the PAPUC and the FERC.
Note 2 — Summary of Significant Accounting Policies
The accompanying condensed consolidated financial statements are unaudited and have been prepared in accordance with the rules and regulations of the SEC. They include all adjustments that we consider necessary for a fair statement of the results for the interim periods presented. Such adjustments consisted only of normal recurring items unless otherwise disclosed. The September 30, 2018, Condensed Consolidated Balance Sheet was derived from audited financial statements but does not include all disclosures required by GAAP.
These financial statements should be read in conjunction with the financial statements and related notes included in the Company’s 2018 Annual Report. Due to the seasonal nature of our businesses, the results of operations for interim periods are not necessarily indicative of the results to be expected for a full year.
Revenue Recognition. Effective October 1, 2018, the Company adopted ASU No. 2014-09, “Revenue from Contracts with Customers,” which, as amended, is included in ASC 606. This new accounting guidance supersedes previous revenue recognition requirements in ASC 605. ASC 606 requires that an entity recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. We adopted this new accounting guidance using the modified retrospective transition method to those contracts which were not completed as of October 1, 2018. Periods prior to October 1, 2018, have not been restated and continue to be reported
10
UGI CORPORATION AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Currency in millions, except per share amounts and where indicated otherwise)
in accordance with ASC 605. The Company recorded a $7.1 reduction to opening retained earnings as of October 1, 2018, to reflect the cumulative effect of ASC 606 on certain contracts not complete as of the date of adoption. The adoption of ASC 606 did not, and is not expected to, have a material impact on the amount or timing of our revenue recognition and on our consolidated net income, cash flows or financial position.
Certain revenues such as revenue from leases, financial instruments and other revenues are not within the scope of ASC 606 because they are not from contracts with customers. Such revenues are accounted for in accordance with other GAAP. Revenue-related taxes collected on behalf of customers and remitted to taxing authorities, principally sales and use taxes, are not included in revenues. Gross receipts taxes at Midstream & Marketing and Electric Utility are presented on a gross basis. The Company has elected to use the practical expedient to expense the costs to obtain contracts when incurred for contracts that have a term less than one year. The costs incurred to obtain contracts that have duration of longer than one year are not material.
See Note 4 for the additional disclosures regarding the Company’s revenue from contracts with customers.
Restricted Cash. Restricted cash principally represents those cash balances in our commodity futures brokerage accounts that are restricted from withdrawal. Upon adoption of revised accounting guidance in October 2018 (see Note 3), restricted cash is included within the Company’s Condensed Consolidated Statements of Cash Flows, with changes in the balance no longer reflected as a separate investing activity. The retrospective application of the new guidance on the previously reported cash flows from investing activities for the three months ended December 31, 2017, resulted in the elimination of the item “Decrease in restricted cash,” which had previously been reported as a use of cash of $9.5.
The following table provides a reconciliation of the total cash, cash equivalents and restricted cash reported on the Condensed Consolidated Balance Sheets to the corresponding amounts reported on the Condensed Consolidated Statements of Cash Flows:
Cash, Cash Equivalents and Restricted Cash | ||||||||||||||||
December 31, 2018 | December 31, 2017 | September 30, 2018 | September 30, 2017 | |||||||||||||
Cash and cash equivalents | $ | 477.6 | $ | 446.4 | $ | 452.6 | $ | 558.4 | ||||||||
Restricted cash | 17.4 | 19.8 | 9.6 | 10.3 | ||||||||||||
Cash, cash equivalents and restricted cash | $ | 495.0 | $ | 466.2 | $ | 462.2 | $ | 568.7 | ||||||||
Earnings Per Common Share. Basic earnings per share attributable to UGI shareholders reflect the weighted-average number of common shares outstanding. Diluted earnings per share attributable to UGI include the effects of dilutive stock options and common stock awards.
Shares used in computing basic and diluted earnings per share are as follows:
Three Months Ended December 31, | ||||||
2018 | 2017 | |||||
Denominator (thousands of shares): | ||||||
Weighted-average common shares outstanding — basic | 174,413 | 173,670 | ||||
Incremental shares issuable for stock options and awards (a) | 3,153 | 3,278 | ||||
Weighted-average common shares outstanding — diluted | 177,566 | 176,948 | ||||
(a) | For the three months ended December 31, 2018 and 2017, there were 30 and 146 shares, respectively, associated with outstanding stock option awards that were excluded from the computation of diluted earnings per share above because their effect was antidilutive. |
Derivative Instruments. Derivative instruments are reported on the Condensed Consolidated Balance Sheets at their fair values, unless the NPNS exception is elected. The accounting for changes in fair value depends upon the purpose of the derivative instrument and whether it is subject to regulatory ratemaking mechanisms or if it qualifies and is designated as a hedge for accounting purposes.
11
UGI CORPORATION AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Currency in millions, except per share amounts and where indicated otherwise)
Certain of our derivative instruments qualify and are designated as cash flow hedges. For cash flow hedges, changes in the fair values of the derivative instruments are recorded in AOCI, to the extent effective at offsetting changes in the hedged item, until earnings are affected by the hedged item. We discontinue cash flow hedge accounting if occurrence of the forecasted transaction is determined to be no longer probable. Hedge accounting is also discontinued for derivatives that cease to be highly effective. We do not designate our commodity and certain foreign currency derivative instruments as hedges under GAAP. Changes in the fair values of these derivative instruments are reflected in net income. Gains and losses on substantially all of the commodity derivative instruments used by UGI Utilities are included in regulatory assets or liabilities because it is probable such gains or losses will be recoverable from, or refundable to, customers. From time to time, we also enter into net investment hedges. Gains and losses on net investment hedges that relate to our foreign operations are included in the cumulative translation adjustment section of AOCI until such foreign net investment is sold or liquidated.
In order to reduce the volatility in net income associated with our foreign operations, principally as a result of changes in the U.S. dollar exchange rate between the euro and British pound sterling, we enter into forward foreign currency exchange contracts. Because these contracts do not qualify for hedge accounting treatment, realized and unrealized gains and losses on these contracts are recorded in “Other non-operating income (expense), net” on the Condensed Consolidated Statements of Income.
Cash flows from derivative instruments, other than certain cross-currency swaps and net investment hedges, if any, are included in cash flows from operating activities on the Condensed Consolidated Statements of Cash Flows. Cash flows from the interest portion of our cross-currency hedges, if any, are included in cash flows from operating activities while cash flows from the currency portion of such hedges, if any, are included in cash flows from financing activities. Cash flows from net investment hedges, if any, are included in cash flows from investing activities on the Condensed Consolidated Statements of Cash Flows.
For a more detailed description of the derivative instruments we use, our accounting for derivatives, our objectives for using them and other information, see Note 14.
Income Taxes. UGI’s consolidated effective income tax rate, defined as total income taxes as a percentage of income (loss) before income taxes, includes amounts associated with noncontrolling interests in the Partnership, which principally comprises AmeriGas Partners and AmeriGas OLP. AmeriGas Partners and AmeriGas OLP are not directly subject to federal income taxes. As a result, UGI’s consolidated effective income tax rate is affected by the amount of income (loss) before income taxes attributable to noncontrolling interests in the Partnership not subject to income taxes.
See Note 6 for discussions regarding the December 22, 2017, enactment of the TCJA in the U.S. and the December 2017 French Finance Bills.
Use of Estimates. The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and costs. These estimates are based on management’s knowledge of current events, historical experience and various other assumptions that are believed to be reasonable under the circumstances. Accordingly, actual results may be different from these estimates and assumptions.
Reclassifications. Certain amounts for the three months ended December 31, 2017, have been reclassified as a result of the adoption of revised accounting guidance pertaining to certain net periodic pension and other postretirement benefit costs and restricted cash (see Note 3). In addition, certain other prior-period amounts have been reclassified to conform to the current-period presentation.
Other non-operating income (expense), net. Included in “Other non-operating income (expense), net,” on the Condensed Consolidated Statements of Income are net gains and losses on forward foreign currency contracts used to reduce volatility in net income associated with our foreign operations, and non-service income (expense) associated with our pension and other postretirement plans.
12
UGI CORPORATION AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Currency in millions, except per share amounts and where indicated otherwise)
Note 3 — Accounting Changes
New Accounting Standards Adopted Effective October 1, 2018
Revenue Recognition. Effective October 1, 2018, the Company adopted new accounting guidance regarding revenue recognition. See Notes 2 and 4 for a detailed description of the impact of the new guidance and related disclosures.
Cloud Computing Implementation Costs. In August 2018, the FASB issued ASU No. 2018-15, “Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract.” The new guidance requires a customer in a cloud computing arrangement that is a service contract to capitalize certain implementation costs as if the arrangement was an internal-use software project. These deferred implementation costs are expensed over the fixed, noncancelable term of the service arrangement plus any reasonably certain renewal periods. The new guidance also requires the entity to present the expense related to the capitalized implementation costs in the same income statement line as the hosting service fees; to classify payments for capitalized implementation costs in the statement of cash flows in the same manner as payments for hosting service fees; and to present the capitalized implementation costs in the balance sheet in the same line item in which prepaid hosting service fees are presented. The new guidance can be applied either retrospectively or prospectively to all implementation costs incurred after the date of adoption. We adopted this ASU effective October 1, 2018, and applied the guidance prospectively to all implementation costs associated with cloud computing arrangements that are service contracts incurred beginning October 1, 2018. The adoption of the new guidance did not have a material impact on our results of operations for the three months ended December 31, 2018.
Stranded Tax Effects in Accumulated Other Comprehensive Income. In February 2018, the FASB issued ASU No. 2018-02, “Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income.” This ASU provides that the stranded tax effects in AOCI resulting from the remeasurement of deferred income taxes associated with items included in AOCI due to the enactment of the TCJA may be reclassified to retained earnings, at the election of the entity, in the period the ASU is adopted. We adopted this ASU effective October 1, 2018. In connection with the adoption of this guidance, we reclassified a benefit of $6.6 from AOCI to opening retained earnings as of October 1, 2018, to reflect the reduction in the federal income tax rate, and the federal benefit of state income taxes, on the components of AOCI.
Pension and Other Postretirement Benefit Costs. In March 2017, the FASB issued ASU No. 2017-07, “Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost.” This ASU requires entities to disaggregate the service cost component from the other components of net periodic benefit cost and present it with compensation costs for related employees in the income statement. The other components are required to be presented elsewhere in the income statement and outside of income from operations. The amendments in this ASU permit only the service cost component to be eligible for capitalization, when applicable. For entities subject to rate regulation, including UGI Utilities, the ASU recognized that in the event a regulator continues to require capitalization of all net periodic benefit costs prospectively, the difference would result in the recognition of a regulatory asset or liability.
The guidance became effective for the Company beginning October 1, 2018, with retrospective adoption for the presentation of pension and postretirement expense on the income statement and a prospective adoption for capitalization. The Company’s Condensed Consolidated Statement of Income for the three months ended December 31, 2017, has been recast to reflect the retrospective adoption for the presentation of the non-service cost component of net periodic pension and other postretirement benefit cost, net of estimated amounts capitalized, within “Other non-operating income (expense), net,” on the Condensed Consolidated Statement of Income. Previously, the non-service cost components were reflected in “Operating and administrative expenses.”
For the three months ended December 31, 2018, the amount of income comprising the non-service cost components of our pension and postretirement benefit plans, net of amounts capitalized, presented in "Other non-operating income (expense), net,” totaled $0.1. For the three months ended December 31, 2017, the amount of expense comprising the non-service cost components of our pension and postretirement benefit plans, net of amounts capitalized, which has been reclassified from "Operating and administrative expenses" to "Other non-operating income (expense), net,” totaled $3.2.
Statement of Cash Flows - Restricted Cash. In November 2016, the FASB issued ASU No. 2016-18, “Statement of Cash Flows: Restricted Cash.” The guidance in this ASU requires that a statement of cash flows explain the change during the period in the total of cash, cash equivalents, as well as restricted cash or restricted cash equivalents. As a result, amounts generally described
13
UGI CORPORATION AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Currency in millions, except per share amounts and where indicated otherwise)
as restricted cash and restricted cash equivalents are included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts on the statement of cash flows. The amendments in the ASU are required to be adopted on a retrospective basis. We adopted this ASU effective October 1, 2018. Adoption of this new guidance resulted in a change in presentation of restricted cash on the Condensed Consolidated Statement of Cash Flows; otherwise, this guidance did not have a significant impact on our Condensed Consolidated Statement of Cash Flows and disclosures (see Note 2, “Restricted Cash”).
Accounting Standards Not Yet Adopted
Pension and Other Postretirement Benefit Costs Disclosures. In August 2018, the FASB issued ASU No. 2018-14, “Changes to the Disclosure Requirements for Defined Benefit Plans.” This ASU modifies the disclosure requirements for employers that sponsor defined benefit pension or other postretirement plans by removing and adding certain disclosures for these plans. The amendments in this ASU are effective for interim and annual periods beginning October 1, 2020 (Fiscal 2021). The guidance shall be adopted retrospectively for all periods presented in the financial statements. Early adoption is permitted. The Company is in the process of assessing the impact on its financial statement disclosures from the adoption of the new guidance and determining the period in which the new guidance will be adopted.
Fair Value Measurements Disclosures. In August 2018, the FASB issued ASU No. 2018-13, “Changes to the Disclosure Requirements for Fair Value Measurement.” This ASU modifies the disclosure requirements for fair value measurements by removing, modifying, or adding certain disclosures. The amendments in this ASU are effective for annual periods beginning October 1, 2020 (Fiscal 2021). The guidance regarding removing and modifying disclosures will be adopted on a retrospective basis and the guidance regarding new disclosures will be adopted on a prospective basis. Early adoption is permitted. The Company is in the process of assessing the impact on its financial statement disclosures from the adoption of the new guidance and determining the period in which the new guidance will be adopted.
Derivatives and Hedging. In August 2017, the FASB issued ASU No. 2017-12, “Targeted Improvements to Accounting for Hedging Activities.” This ASU amends and simplifies existing guidance to allow companies to more accurately present the economic effects of risk management activities in the financial statements. The amendments in this ASU are effective for the Company for interim and annual periods beginning October 1, 2019 (Fiscal 2020). Early adoption is permitted. For cash flow and net investment hedges as of the adoption date, the guidance requires a modified retrospective approach. The amended presentation and disclosure guidance is required prospectively. The Company is in the process of assessing the impact on its financial statements from the adoption of the new guidance and determining the period in which the new guidance will be adopted.
Leases. In February 2016, the FASB issued ASU No. 2016-02, "Leases." This ASU, as subsequently updated, amends existing guidance to require entities that lease assets to recognize the assets and liabilities for the rights and obligations created by those leases on the balance sheet. The new guidance also requires additional disclosures about the amount, timing and uncertainty of cash flows from leases. The amendments in this ASU are effective for the Company for interim and annual periods beginning October 1, 2019 (Fiscal 2020). Early adoption is permitted. Lessees must apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements unless an entity chooses the transition option in ASU 2018-11, “Leases: Targeted Improvements” which, among other things, provides entities with a transition option to recognize the cumulative-effect adjustment from the modified retrospective application to the opening balance of retained earnings in the period of adoption. We will adopt ASU No. 2016-02, as updated, effective October 1, 2019, and expect to elect the transition option which would allow the Company to maintain historical presentation for periods before October 1, 2019. The Company has completed a preliminary assessment for evaluating the impact of the guidance and anticipates that its adoption will result in a significant amount of right-of-use assets and lease liabilities for leases in effect at the adoption date. The Company has begun implementation activities including accumulating contracts and lease data in formats compatible with a new lease management system that will assist with the initial adoption of the standard.
Note 4 — Revenue from Contracts with Customers
The Company recognizes revenue when control of promised goods or services is transferred to our customers in an amount that reflects the consideration to which we expect to be entitled in exchange for those goods or services. The Company generally has the right to consideration from a customer in an amount that corresponds directly with the value to the customer for our performance completed to date. As such, we have elected to recognize revenue in the amount to which we have a right to invoice except in the case of certain UGI Utilities’ large delivery service customers and Midstream & Marketing’s peaking contracts for which we
14
UGI CORPORATION AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Currency in millions, except per share amounts and where indicated otherwise)
recognize revenue on a straight-line basis over the term of the contract, consistent with when the performance obligations are satisfied by the Company.
We do not have a significant financing component in our contracts because we receive payment shortly before, at, or shortly after the transfer of control of the good or service. Because the period between the time the performance obligation is satisfied and payment is received is one year or less, the Company has elected to apply the significant financing component practical expedient and no amount of consideration has been allocated as a financing component.
The Company’s revenues from contracts with customers are discussed below.
Utility Revenues
UGI Utilities supplies natural gas and electricity and provides distribution services of natural gas and electricity to residential, commercial, and industrial customers who are generally billed at standard regulated tariff rates approved by the PAPUC through the ratemaking process. Tariff rates include a component that provides for a reasonable opportunity to recover operating costs and expenses and to earn a return on net investment, and a component that provides for the recovery, subject to reasonableness reviews, of PGC and DS costs.
Customers may choose to purchase their natural gas and electricity from Gas Utility or Electric Utility, or, alternatively, may contract separately with alternate suppliers. Accordingly, our contracts with customers comprise two promised goods or services: (1) delivery service of natural gas and electricity through the Company’s utility distribution systems and (2) the natural gas or electricity commodity itself for those customers who choose to purchase the natural gas or electricity directly from the Company. Revenue is not recorded for the sale of natural gas or electricity to customers who have contracted separately with alternate suppliers. For those customers who choose to purchase their natural gas or electricity from the Company, the performance obligation includes both the supply of the commodity and the delivery service.
The terms of our core market customer contracts are generally considered day-to-day as customers can discontinue service at any time without penalty. Performance obligations are generally satisfied over time as the natural gas or electricity is delivered to customers, at which point the customers simultaneously receive and consume the benefits provided by the delivery service and, when applicable, the commodity. Amounts are billed to customers based upon the reading of a customer’s meter which occurs on a cycle basis throughout each reporting period. An unbilled amount is recorded at the end of each reporting period based upon estimated amounts of natural gas or electricity delivered to customers since the date of the last meter reading. These unbilled estimates consider various factors such as historical customer usage patterns, customer rates and weather.
UGI Utilities has certain fixed-term contracts with large commercial and industrial customers to provide natural gas delivery services at contracted rates and at volumes generally based on the customer’s needs. The performance obligation to provide the contracted delivery service for these large commercial and industrial customers is satisfied over time and revenue is generally recognized on a straight-line basis.
UGI Utilities makes off-system sales whereby natural gas delivered to our system in excess of amounts needed to fulfill our distribution system needs is sold to other customers, primarily other distributors of natural gas, based on an agreed-upon price and volume between the Company and the counterparty. Gas Utility also sells excess capacity whereby interstate pipeline capacity in excess of amounts needed to meet our customer obligations is sold to other distributors of natural gas based upon an agreed-upon rate. Off-system sales and capacity releases are generally entered into one month at a time and comprise the sale of a specific volume of gas or pipeline capacity at a specific delivery point or points over a specific time. As such, performance obligations associated with off-system sales and capacity release customers are satisfied, and associated revenue is recorded, when the agreed upon volume of natural gas is delivered or capacity is provided, and title is transferred, in accordance with the contract terms.
Electric Utility provides transmission services to PJM by allowing PJM to access Electric Utility’s electricity transmission facilities. In exchange for providing access, PJM pays Electric Utility consideration determined by a formula-based rate approved by FERC. The formula-based rate, which is updated annually, allows recovery of costs incurred to provide transmission services and return on transmission-related net investment. We recognize revenue over time as we provide transmission service.
Other Utility revenues represent revenues from other ancillary services provided to customers and are generally recorded as the service is provided to customers.
15
UGI CORPORATION AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Currency in millions, except per share amounts and where indicated otherwise)
Non-Utility Revenues
LPG. AmeriGas Propane and UGI International record revenue principally from the sale of LPG to retail and wholesale customers. The primary performance obligation associated with the sale of LPG is the delivery of propane to (1) the customer’s point of delivery for retail customers and (2) the customer’s specified location where LPG is picked up by wholesale customers, at which point control of the propane is transferred to the customer, the performance obligation is satisfied, and the associated revenue is recognized. For contracts with retail customers that consume LPG from a metered tank, we recognize revenue as LPG is consumed, at which point we have right to invoice, and generally invoice monthly based on consumption.
Contracts with customers comprise different types of contracts with varying length terms, fixed or variable prices, and fixed or variable quantities. Contracts with our residential customers, which comprise a substantial number of our customer contracts, are generally one year or less. Customer contracts for the sale of LPG include fixed-price, fixed-quantity contracts under which LPG is provided to a customer at a fixed price and a fixed volume, and contracts that provide for the sale of propane at market prices at date of delivery with no fixed volumes. AmeriGas Propane offers contracts that permit the customer to lock in a fixed price for their volumes for a fee and also provide the customer with the option to pre-buy a fixed amount of propane at a fixed price. Amounts received under pre-buy arrangements are recorded as a contract liability when received and recorded as revenue when LPG is delivered and control is transferred to the customer. Fees associated with fixed-price contracts are recorded as contract liabilities and recorded ratably over the contract period.
AmeriGas Propane and UGI International also distribute LPG to customers in portable cylinders. Under certain contracts, filled cylinders are delivered, and control is transferred, to a reseller. In such instances, the reseller is our customer and we record revenue upon delivery to the reseller. Under other contracts, filled cylinders are delivered to a reseller, but the Company retains control of the cylinders. In such instances, we record revenue at the time the reseller transfers control of the cylinder to the end user.
Certain retail LPG customers receive credits which we account for as variable consideration. We estimate these credits based upon past practices and historical customer experience and we reduce our revenues recognized for these credits.
Energy Marketing. Midstream & Marketing and UGI International operate energy marketing businesses that sell energy commodities, principally natural gas and electricity, to residential, commercial, industrial and wholesale customers. In addition, UGI International provides system balancing and procurement services to other energy marketers in the Netherlands.
Midstream & Marketing and UGI International market natural gas and electricity on full-requirements or agreed-upon volume bases under contracts with varying length terms and at fixed or floating prices that are based on market indices adjusted for differences in price between the market location and delivery locations. Performance obligations associated with these contracts primarily comprise the delivery of the natural gas and electricity over a contractual period of time. Performance obligations also include other energy-related ancillary services provided to customers such as capacity. For performance obligations that are satisfied at a point in time such as the delivery of natural gas, revenue is recorded when customers take control of the natural gas. Revenue is recorded for performance obligations that qualify as a series, when customers consume the natural gas or electricity delivered, which corresponds to the amount invoiced to the customer. For transactions where the price or volume is not fixed, the transaction price is not determined until delivery occurs. The billed amount, and the revenue recorded, is based upon consumption by the customer.
In addition to providing natural gas and electricity to end use customers, our energy marketing business in the Netherlands has contracts with third-party natural gas and electricity marketers to provide BRP services in the electricity and natural gas markets in the Netherlands. These contracts are typically multi-year agreements and include full BRP services which include, among other things, estimating, procuring and scheduling all energy requirements to meet third-party marketers’ needs, or provide more limited system procurement and balancing services. The amount of revenue recognized from our BRP customers is based upon the amount of energy delivered with respect to these agreements, and the level of BRP services provided. We typically receive payments from our BRP customers one month in advance of our performing the related services. Amounts received in advance are deferred on the balance sheet as contract liabilities. Based upon an evaluation of the terms and conditions of the BRP contracts and our ability to control the goods or services provided to the third-party marketers, in addition to other factors, we are considered a principal in these contracts and are required to record the revenue associated with the sale of energy to the third-party energy marketers on a gross basis. We record the associated revenue ratably over time, typically monthly, as the performance obligations are satisfied.
Midstream. Midstream & Marketing provides natural gas pipeline transportation, natural gas gathering and natural gas underground storage services, which generally contain a performance obligation for the Company to have availability to transport or store a
16
UGI CORPORATION AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Currency in millions, except per share amounts and where indicated otherwise)
product. Additionally, the Company provides stand-ready services to sell supplemental energy products and related services, primarily LNG and propane-air mixtures during periods of high demand that typically results from cold weather. The Company also sells LNG to end-user customers for use by trucks, drilling rigs and other motored vehicles and equipment, and facilities that are located off the natural gas grid.
Contracts for natural gas transportation and gathering services are typically long-term contracts with terms of up to 30 years, while contracts for storage are typically for a one-year or multiple storage season periods. Contracts to provide natural gas during periods of high demand have terms of up to 15 years. Contracts to sell LNG for trucks, drilling rigs and other motor vehicles and facilities are typically short-term (less than one year). Depending on the type of services provided or goods sold, midstream revenues may consist of demand rates, commodity rates, and transportation rates and may include other fees for ancillary services. Pipeline transportation, natural gas gathering and storage services provided and services to stand ready to sell supplemental energy products and services each are considered to have a single performance obligation satisfied through the passage of time ratably based upon providing a stand-ready service on a monthly basis. Contracts to sell LNG to end-user customers contain performance obligations to deliver LNG over the term of the contract and revenue is recognized at a point in time when the control of the energy products is transferred to the customer. The price in the contract corresponds to our efforts to satisfy the performance obligation and reflects the consideration we expect to receive for the satisfied performance obligation, and, therefore, the revenue is recognized based on the volume delivered and the price within the contract. In cases where shipping & handling occurs prior to the LNG being delivered to the customer’s storage vessel, we have elected to treat this as a cost of fulfillment and not a separate performance obligation. Revenues are typically billed and payment received monthly. Advance fees received from customers for stand-ready services are deferred as contract liabilities and revenue is recognized ratably over time as the performance obligation is satisfied over a period less than one year.
Electricity Generation. Midstream & Marketing also sells power generated from our electricity generation assets in the wholesale electricity markets administered by PJM regional transmission organization. Power contracts with PJM consist of the sale of power, capacity and ancillary services, all of which are considered a bundle of various services. Performance obligations are satisfied over time, generally on a daily basis, as electricity is delivered to and simultaneously consumed by the customer. As such, the Company has elected to recognize revenue in the amount to which we have a right to invoice which is based on market prices at the time of the delivery of the electricity to the customers.
Other. Other revenues from contracts with customers are generated primarily from services and products provided by Midstream & Marketing’s HVAC business and AmeriGas Propane’s parts and services business. The performance obligations of these businesses include installation, repair and warranty agreements associated with HVAC equipment and installation services provided for combined heat and power and solar panel installations. For installation and repair goods and services, the performance obligations under these contracts are satisfied, and revenue is recognized, as control of the product is transferred or the services are rendered. For warranty services, revenue is recorded ratably over the warranty period. Other LPG revenues from contracts with customers are generated primarily from certain fees AmeriGas Partners and UGI International charge associated with the delivery of LPG, including hazmat safety compliance, inspection, metering, installation, fuel recovery and certain other services. Revenues from fees are typically recorded when the LPG is delivered to the customer or the associated service is completed.
Contract Balances
The timing of revenue recognition may differ from the timing of invoicing to customers or cash receipts. Contract assets represent our right to consideration after the performance obligations have been satisfied when such right is conditioned on something other than the passage of time. Contract assets were not material at December 31, 2018. Substantially all of our receivables are unconditional rights to consideration and are included in “Accounts receivable” and, in the case of UGI Utilities, “Accrued utility revenues” on the Condensed Consolidated Balance Sheets. Amounts billed are generally due within the following month.
Contract liabilities arise when payment from a customer is received before the performance obligations have been satisfied and represent the Company’s obligations to transfer goods or services to a customer for which we have received consideration. The balance of contract liabilities was $94.0 and $115.6 at December 31, 2018 and October 1, 2018, respectively, and are included in “Other current liabilities” on the Condensed Consolidated Balance Sheets. Revenue recognized for the three months ended December 31, 2018, from the amount included in contract liabilities at October 1, 2018 was $58.1.
17
UGI CORPORATION AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Currency in millions, except per share amounts and where indicated otherwise)
Revenue Disaggregation
The following table presents our disaggregated revenues by reportable segment for the three months ended December 31, 2018:
Total | Eliminations | AmeriGas Propane | UGI International | Midstream & Marketing (a) | UGI Utilities (a) | Corporate & Other | ||||||||||||||||||||||
Revenues from contracts with customers: | ||||||||||||||||||||||||||||
Utility: | ||||||||||||||||||||||||||||
Core Market: | ||||||||||||||||||||||||||||
Residential | $ | 175.7 | $ | — | $ | — | $ | — | $ | — | $ | 175.7 | $ | — | ||||||||||||||
Commercial & Industrial | 67.6 | — | — | — | — | 67.6 | — | |||||||||||||||||||||
Large delivery service | 39.5 | — | — | — | — | 39.5 | — | |||||||||||||||||||||
Off-system sales and capacity releases | 15.2 | (22.9 | ) | — | — | — | 38.1 | — | ||||||||||||||||||||
Other (b) | 0.5 | (0.7 | ) | — | — | — | 1.2 | — | ||||||||||||||||||||
Total Utility | 298.5 | (23.6 | ) | — | — | — | 322.1 | — | ||||||||||||||||||||
Non-Utility: | ||||||||||||||||||||||||||||
LPG: | ||||||||||||||||||||||||||||
Retail | 1,229.7 | — | 721.9 | 507.8 | — | — | — | |||||||||||||||||||||
Wholesale | 60.0 | — | 21.0 | 39.0 | — | — | — | |||||||||||||||||||||
Energy Marketing | 468.9 | (47.5 | ) | — | 143.1 | 373.3 | — | — | ||||||||||||||||||||
Midstream: | ||||||||||||||||||||||||||||
Pipeline | 19.4 | — | — | — | 19.4 | — | — | |||||||||||||||||||||
Peaking | 2.0 | (38.7 | ) | — | — | 40.7 | — | — | ||||||||||||||||||||
Other | 1.0 | — | — | — | 1.0 | — | — | |||||||||||||||||||||
Electricity Generation | 11.7 | — | — | — | 11.7 | — | — | |||||||||||||||||||||
Other | 84.0 | (0.7 | ) | 60.6 | 12.4 | 11.7 | — | — | ||||||||||||||||||||
Total Non-Utility | 1,876.7 | (86.9 | ) | 803.5 | 702.3 | 457.8 | — | — | ||||||||||||||||||||
Total revenues from contracts with customers | 2,175.2 | (110.5 | ) | 803.5 | 702.3 | 457.8 | 322.1 | — | ||||||||||||||||||||
Other revenues (c) | 25.0 | (1.1 | ) | 16.7 | 8.4 | 1.6 | 0.6 | (1.2 | ) | |||||||||||||||||||
Total revenues | $ | 2,200.2 | $ | (111.6 | ) | $ | 820.2 | $ | 710.7 | $ | 459.4 | $ | 322.7 | $ | (1.2 | ) | ||||||||||||
(a) | Includes intersegment revenues principally among Midstream & Marketing, UGI Utilities and AmeriGas Propane. |
(b) | UGI Utilities includes unallocated negative surcharge revenue of $(4.1) as a result of a PAPUC Order issued May 17, 2018, related to TCJA (see Note 8). |
(c) | Primarily represents revenues from tank rentals at AmeriGas Propane and UGI International, revenues from certain gathering assets at Midstream & Marketing, and gains and losses on commodity derivative instruments not associated with current-period transactions reflected in Corporate & Other, all of which are not within the scope of ASC 606 and accounted for in accordance with other GAAP. |
Remaining Performance Obligations
The Company has elected to use practical expedients as allowed in ASC 606 to exclude disclosures related to the aggregate amount of the transaction price allocated to certain performance obligations that are unsatisfied as of the end of the reporting period because these contracts have an initial expected term of one year or less, or we have a right to bill the customer in an amount that corresponds directly with the value of services provided to the customer to date. Certain contracts with customers at Midstream & Marketing and UGI Utilities contain minimum future performance obligations through 2047 and 2053, respectively. At December 31, 2018, Midstream & Marketing and UGI Utilities expect to record approximately $1.5 billion and $0.2 billion of revenues, respectively, related to the minimum future performance obligations over the remaining terms of the related contracts.
18
UGI CORPORATION AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Currency in millions, except per share amounts and where indicated otherwise)
Note 5 — Inventories
Inventories comprise the following:
December 31, 2018 | September 30, 2018 | December 31, 2017 | ||||||||||
Non-utility LPG and natural gas | $ | 206.7 | $ | 231.7 | $ | 216.4 | ||||||
Gas Utility natural gas | 34.9 | 37.3 | 34.6 | |||||||||
Materials, supplies and other | 52.1 | 49.2 | 56.3 | |||||||||
Total inventories | $ | 293.7 | $ | 318.2 | $ | 307.3 | ||||||
At December 31, 2018, UGI Utilities was a party to five principal SCAAs with terms of up to three years. Pursuant to the SCAAs, UGI Utilities has, among other things, released certain storage and transportation contracts for the terms of the SCAAs. UGI Utilities also transferred certain associated storage inventories upon commencement of the SCAAs, will receive a transfer of storage inventories at the end of the SCAAs, and makes payments associated with refilling storage inventories during the terms of the SCAAs. The historical cost of natural gas storage inventories released under the SCAAs, which represents a portion of Gas Utility’s total natural gas storage inventories, and any exchange receivable (representing amounts of natural gas inventories used by the other parties to the agreement but not yet replenished for which UGI Utilities has the rights), are included in the caption “Gas Utility natural gas” in the table above.
As of December 31, 2018, UGI Utilities had SCAAs with Energy Services, the effects of which are eliminated in consolidation, and with a non-affiliate. The carrying value of gas storage inventories released under the SCAAs with the non-affiliate at December 31, 2018, September 30, 2018 and December 31, 2017, comprising 1.9 bcf, 2.3 bcf and 1.8 bcf of natural gas, was $4.6, $5.4, and $5.1, respectively.
Note 6 — Income Taxes
TCJA
On December 22, 2017, the TCJA was enacted into law. Among the significant changes resulting from the law, the TCJA reduced the U.S. federal income tax rate from 35% to 21%, effective January 1, 2018, created a territorial tax system with a one-time mandatory “toll tax” on previously un-repatriated foreign earnings, and allowed for immediate capital expensing of certain qualified property. It also applied restrictions on the deductibility of interest expense, eliminated bonus depreciation for regulated utilities and certain FERC-regulated property beginning in Fiscal 2019, and applied a broader application of compensation limitations.
In accordance with GAAP as determined by ASC 740 we are required to record the effects of tax law changes in the period enacted. As further discussed below, our results for the three months ended December 31, 2017, contained provisional estimates of the impact of the TCJA. These amounts were considered provisional because they used estimates for which tax returns had not yet been filed and because estimated amounts could have been impacted by future regulatory and accounting guidance if and when issued. We adjusted provisional amounts as further information became available and as we refined our calculations. As permitted by SEC Staff Accounting Bulletin No. 118, these adjustments occurred during the reasonable “measurement period” defined as twelve months from the date of enactment. During the three months ended December 31, 2018, adjustments to provisional amounts recorded in prior periods were not material.
As a result of the enactment of the TCJA on December 22, 2017, during the three months ended December 31, 2017, we reduced our net deferred income tax liabilities due to the remeasuring of our existing federal deferred income tax assets and liabilities. Because current law requires that excess deferred income taxes associated with UGI Utilities’ regulated utility plant assets are to be amortized no more rapidly than over the remaining lives of the assets that gave rise to the excess deferred taxes, UGI Utilities recorded a regulatory liability related to such excess deferred income taxes (see Note 8).
For the three months ended December 31, 2017, discrete deferred income tax adjustments reduced income tax expense by $166.0 and consisted primarily of the following items:
(1)a $180.3 reduction in net deferred tax liabilities in the U.S from the reduction of the U.S. tax rate;
19
UGI CORPORATION AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Currency in millions, except per share amounts and where indicated otherwise)
(2)the establishment of $12.6 of valuation allowances related to deferred tax assets impacted by U.S. tax law changes; and
(3)a $1.7 “toll tax” on un-repatriated foreign earnings.
For the three months ended December 31, 2018 and 2017, we included the estimated impacts of the TCJA in determining our estimated annual effective income tax rates. We are subject to a 21.0% U.S. federal tax rate in Fiscal 2019. We were subject to a blended U.S. federal tax rate of 24.5% for Fiscal 2018 because our fiscal year contained the effective date of the rate change from 35% to 21% on January 1, 2018. As a result, the U.S. federal income tax rates included in our estimated annual effective tax rates used for the three months ended December 31, 2018 and 2017 were based on rates of 21.0% and 24.5%, respectively. Our estimated annual effective tax rate was not impacted by any regulatory action taken by the PAPUC.
December 2017 French Finance Bills
In December 2017, the December 2017 French Finance Bills were approved. One impact of the December 2017 French Finance Bills was an increase in the Fiscal 2018 corporate income tax rate in France from 34.4% to 39.4%. The December 2017 French Finance Bills also include measures to reduce the corporate income tax rate to 25.8%, effective for fiscal years starting after January 1, 2022 (Fiscal 2023). As a result of the future corporate income tax rate reduction effective in Fiscal 2023, during the three months ended December 31, 2017, the Company reduced its net French deferred income tax liabilities and recognized an estimated deferred tax benefit of $17.3. The estimated annual effective income tax rate used in determining income taxes for the three months ended December 31, 2017, reflected the impact of the single year Fiscal 2018 income tax rate as a result of the December 2017 French Finance Bills. The impact of the single year rate change increased income tax expense for the three months ended December 31, 2017, by $3.9.
Note 7 — Goodwill and Intangible Assets
Goodwill and intangible assets comprise the following:
December 31, 2018 | September 30, 2018 | December 31, 2017 | ||||||||||
Goodwill (not subject to amortization) | $ | 3,154.8 | $ | 3,160.4 | $ | 3,185.5 | ||||||
Intangible assets: | ||||||||||||
Customer relationships, noncompete agreements and other | $ | 853.0 | $ | 848.6 | $ | 862.0 | ||||||
Trademarks and tradenames | 7.9 | 7.9 | — | |||||||||
Accumulated amortization | (405.4 | ) | (393.2 | ) | (355.0 | ) | ||||||
Intangible assets, net (definite-lived) | 455.5 | 463.3 | 507.0 | |||||||||
Trademarks and tradenames (indefinite-lived) | 49.7 | 50.3 | 134.9 | |||||||||
Total intangible assets, net | $ | 505.2 | $ | 513.6 | $ | 641.9 | ||||||
The changes in goodwill and intangible assets are primarily due to acquisitions and the effects of foreign currency translation. Amortization expense of intangible assets was $14.6 and $14.8 for the three months ended December 31, 2018 and 2017, respectively. Amortization expense included in “Cost of sales” on the Condensed Consolidated Statements of Income was not material. The estimated aggregate amortization expense of intangible assets for the remainder of Fiscal 2019 and for the next four fiscal years is as follows: remainder of Fiscal 2019 — $43.4; Fiscal 2020 — $56.7; Fiscal 2021 — $53.4; Fiscal 2022 — $50.4; Fiscal 2023 — $48.9.
20
UGI CORPORATION AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Currency in millions, except per share amounts and where indicated otherwise)
Note 8 — Utility Regulatory Assets and Liabilities and Regulatory Matters
For a description of the Company’s regulatory assets and liabilities other than those described below, see Note 8 in the Company’s 2018 Annual Report. Other than removal costs, UGI Utilities does not recover a rate of return on its regulatory assets. The following regulatory assets and liabilities associated with UGI Utilities are included in our accompanying Condensed Consolidated Balance Sheets:
December 31, 2018 | September 30, 2018 | December 31, 2017 | ||||||||||
Regulatory assets: | ||||||||||||
Income taxes recoverable | $ | 115.2 | $ | 110.1 | $ | 126.5 | ||||||
Underfunded pension and postretirement plans | 85.3 | 87.1 | 138.3 | |||||||||
Environmental costs | 58.5 | 58.8 | 60.8 | |||||||||
Removal costs, net | 31.3 | 32.0 | 31.4 | |||||||||
Other | 8.5 | 13.0 | 5.8 | |||||||||
Total regulatory assets | $ | 298.8 | $ | 301.0 | $ | 362.8 | ||||||
Regulatory liabilities (a): | ||||||||||||
Postretirement benefits | $ | 17.3 | $ | 17.8 | $ | 17.3 | ||||||
Deferred fuel and power refunds | 22.2 | 36.7 | 12.7 | |||||||||
State tax benefits — distribution system repairs | 23.5 | 22.6 | 19.1 | |||||||||
PAPUC temporary rates order | 24.8 | 24.4 | — | |||||||||
Excess federal deferred income taxes | 280.9 | 285.2 | 303.9 | |||||||||
Other | 4.8 | 3.5 | 4.5 | |||||||||
Total regulatory liabilities | $ | 373.5 | $ | 390.2 | $ | 357.5 | ||||||
(a) | Regulatory liabilities are recorded in “Other current liabilities” and “Other noncurrent liabilities” on the Condensed Consolidated Balance Sheets. |
Deferred fuel and power refunds. Gas Utility’s and Electric Utility’s tariffs contain clauses that permit recovery of all prudently incurred purchased gas and power costs through the application of PGC rates in the case of Gas Utility and DS tariffs in the case of Electric Utility. The clauses provide for periodic adjustments to PGC and DS rates for differences between the total amount of purchased gas and electric generation supply costs collected from customers and recoverable costs incurred. Net undercollected costs are classified as a regulatory asset and net overcollections are classified as a regulatory liability.
Gas Utility uses derivative instruments to reduce volatility in the cost of gas it purchases for retail core-market customers. Realized and unrealized gains or losses on natural gas derivative instruments are included in deferred fuel costs or refunds. Net unrealized gains (losses) on such contracts at December 31, 2018, September 30, 2018 and December 31, 2017 were $0.8, $2.9 and $(1.7), respectively.
PAPUC Temporary Rates Order. On May 17, 2018, the PAPUC ordered each regulated utility currently not in a general base rate case proceeding, including UGI Gas, PNG and CPG, to reduce their rates through the establishment of a negative surcharge applied to bills rendered on or after July 1, 2018. The temporary negative surcharge will be reconciled at the end of each fiscal year to actual tax savings realized. Any difference in the amount of bill credit received by customers and the amount of benefits received by the Company during the period the negative surcharge is in effect is reconciled in the calculation of a new negative surcharge effective January 1 of the subsequent calendar year. The negative surcharge will remain in place until the effective date of new rates established in the utility’s next general base rate proceeding. For the merged Gas Utility, such negative surcharge reduced base rate revenues by 5.78%, 3.90% and 8.19%, respectively, for the UGI South, UGI North and UGI Central rate districts for the three months ended December 31, 2018 and is subject to reconciliation during the period the negative surcharges remain in effect.
In its May 17, 2018 Order, the PAPUC also required Pennsylvania utilities to establish a regulatory liability for tax benefits that accrued during the period beginning January 1, 2018 through June 30, 2018, resulting from the reduced federal tax rate. The rate treatment of this regulatory liability, plus accrued interest, for each Gas Utility rate district will be addressed in a future proceeding and the Company cannot predict the ultimate treatment of this liability. In UGI Gas’s base rate proceeding filed January 28, 2019 (see “Base Rate Filings” below), UGI Gas has proposed a 4.5% negative surcharge applicable to all customer distribution service
21
UGI CORPORATION AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Currency in millions, except per share amounts and where indicated otherwise)
bills to return $26.2 of tax benefits experienced by UGI Utilities over the period January 1, 2018 to June 30, 2018, inclusive of interest, thereby satisfying a requirement to make a proposal for distributing those benefits within three years of the May 17, 2018 Order. The negative surcharge will become effective for a twelve-month period beginning on the effective date of the new base rates.
For Pennsylvania utilities that were in a general base rate proceeding, including Electric Utility, no negative surcharge applies. The tax benefits that accrued during the period January 1, 2018 through October 26, 2018, the date before Electric Utility’s base rate case became effective (see below), were refunded to Electric Utility ratepayers through a one-time bill credit.
Excess federal deferred income taxes. This regulatory liability is the result of remeasuring UGI Utilities’ federal deferred income tax liabilities on utility plant due to the enactment of the TCJA on December 22, 2017 (see Note 6). In order for our utility assets to continue to be eligible for accelerated tax depreciation, current law requires that excess federal deferred income taxes resulting from the remeasurement be amortized no more rapidly than over the remaining lives of the assets that gave rise to the excess federal deferred income taxes, ranging from 1 year to approximately 65 years. This regulatory liability has been increased to reflect the tax benefit generated by the amortization of the excess deferred federal income taxes and is being amortized and credited to tax expense.
Other Regulatory Matters
Utility Merger. On March 8, 2018 and March 13, 2018, UGI Utilities filed merger authorization requests with the PAPUC and MDPSC, respectively, to merge PNG and CPG into UGI Utilities, with a targeted effective date of October 1, 2018. After receiving all necessary FERC, MDPSC, and PAPUC approvals, CPG and PNG were merged into UGI Utilities effective October 1, 2018. Consistent with the MDPSC order issued July 25, 2018, and the PAPUC order issued September, 26, 2018, the former CPG, PNG and UGI Utilities, Inc. Gas Division service territories became the UGI Central, UGI North and UGI South rate districts of the UGI Utilities, Inc. Gas Division, respectively, without any ratemaking change. UGI Utilities’ obligations under the settlement approved by the PAPUC include various non-monetary conditions requiring UGI Utilities to maintain separate accounting-type schedules for limited future ratemaking purposes.
Base Rate Filings. On January 28, 2019, UGI Gas filed a request with the PAPUC to increase its operating revenues for residential, commercial and industrial customers by $71.1 annually. The requested rate increase applies to the consolidated UGI Central, UGI North and UGI South rate districts. The increased revenues would fund ongoing system improvements and operations necessary to maintain safe and reliable natural gas service and fund new programs designed to promote and reward customers’ efforts to increase efficient use of natural gas. Additionally, UGI Gas has proposed a 4.5% negative surcharge applicable to all customer distribution service bills to return $26.2 of tax benefits experienced by UGI Utilities over the period January 1, 2018 to June 30, 2018, inclusive of interest. As proposed, the negative surcharge will become effective for a twelve-month period beginning on the effective date of the new base rates. UGI Gas is requesting that the new gas rates become effective March 29, 2019. However, the PAPUC typically suspends the effective date for general base rate proceedings for a period not to exceed nine months after the filing date to allow for investigation and public hearings. UGI Utilities cannot predict the timing or the ultimate outcome of the rate case review process.
On January 26, 2018, Electric Utility filed a rate request with the PAPUC to increase its annual base distribution revenues by $9.2, which was later reduced by Electric Utility to $7.7 to reflect the impact of the TCJA and other adjustments. The increased revenues would fund ongoing system improvements and operations necessary to maintain safe and reliable electric service. On October 25, 2018, the PAPUC approved a final order providing for a $3.2 annual base distribution rate increase for Electric Utility, effective October 27, 2018. As part of the final order, Electric Utility provided customers with a one-time $0.2 billing credit associated with 2018 TCJA tax benefits. On November 26, 2018, the Pennsylvania Office of Consumer Advocate filed an appeal to the Pennsylvania Commonwealth Court challenging the PAPUC’s acceptance of the UGI Utilities’ use of a fully projected future test year and handling of consolidated federal income tax benefits. UGI Utilities cannot predict the ultimate outcome of this appeal.
On January 19, 2017, PNG (now the UGI North rate district of Gas Utility) filed a rate request with the PAPUC to increase PNG’s annual base operating revenues for residential, commercial and industrial customers by $21.7 annually. The increased revenues would fund ongoing system improvements and operations necessary to maintain safe and reliable natural gas service. On June 30, 2017, all active parties supported the filing of a Joint Petition for Approval of Settlement of all issues with the PAPUC providing for an $11.3 PNG annual base distribution rate increase. On August 31, 2017, the PAPUC approved the Joint Petition and the increase became effective October 20, 2017.
22
UGI CORPORATION AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Currency in millions, except per share amounts and where indicated otherwise)
Manor Township, Pennsylvania Natural Gas Incident Complaint. In connection with a July 2, 2017, explosion in Manor Township, Lancaster County, Pennsylvania, that resulted in the death of one UGI Utilities employee and injuries to two UGI Utilities employees and one sewer authority employee, and destroyed two residences and damaged several other homes, the BIE filed a formal complaint at the PAPUC in which BIE alleged that UGI Utilities committed multiple violations of federal and state gas pipeline regulations in connection with its emergency response leading up to the explosion, and it requested that the PAPUC order UGI Utilities to pay approximately $2.1 in civil penalties, which is the maximum allowable fine. On November 16, 2018, UGI Utilities filed its formal written answer contesting the BIE complaint. The matter remains pending before the PAPUC.
Note 9 — Energy Services Accounts Receivable Securitization Facility
Energy Services has a Receivables Facility currently scheduled to expire in October 2019. The Receivables Facility, as amended, provides Energy Services with the ability to borrow up to $150 of eligible receivables during the period November to April and up to $75 of eligible receivables during the period May to October. Energy Services uses the Receivables Facility to fund working capital, margin calls under commodity futures contracts, capital expenditures, dividends and for general corporate purposes.
Under the Receivables Facility, Energy Services transfers, on an ongoing basis and without recourse, its trade accounts receivable to its wholly owned, special purpose subsidiary, ESFC, which is consolidated for financial statement purposes. ESFC, in turn, has sold and, subject to certain conditions, may from time to time, sell an undivided interest in some or all of the receivables to a major bank. Amounts sold to the bank are reflected as “Short-term borrowings” on the Condensed Consolidated Balance Sheets. ESFC was created and has been structured to isolate its assets from creditors of Energy Services and its affiliates, including UGI. Trade receivables sold to the bank remain on the Company’s balance sheet and the Company reflects a liability equal to the amount advanced by the bank. The Company records interest expense on amounts owed to the bank. Energy Services continues to service, administer and collect trade receivables on behalf of the bank, as applicable. Losses on sales of receivables to the bank during the three months ended December 31, 2018 and 2017, which are included in “Interest expense” on the Condensed Consolidated Statements of Income, were not material.
Information regarding the trade receivables transferred to ESFC and the amounts sold to the bank for the three months ended December 31, 2018 and 2017, as well as the balance of ESFC trade receivables at December 31, 2018, September 30, 2018 and December 31, 2017, is as follows:
Three Months Ended December 31, | ||||||||
2018 | 2017 | |||||||
Trade receivables transferred to ESFC during the period | $ | 392.6 | $ | 270.6 | ||||
ESFC trade receivables sold to the bank during the period | $ | 25.0 | $ | 48.0 | ||||
December 31, 2018 | September 30, 2018 | December 31, 2017 | ||||||||||
ESFC trade receivables — end of period (a) | $ | 135.4 | $ | 65.0 | $ | 101.0 | ||||||
(a) | At December 31, 2018, September 30, 2018, and December 31, 2017, the amounts of ESFC trade receivables sold to the bank were $10.0, $2.0 and $45.0, respectively. Amounts sold to the bank are reflected as “Short-term borrowings” on the Condensed Consolidated Balance Sheets. |
Note 10 — Debt
UGI International. On October 18, 2018, UGI International, LLC, a wholly owned second-tier subsidiary of UGI, entered into the 2018 UGI International Credit Facilities Agreement, a five-year unsecured Senior Facilities Agreement with a consortium of banks consisting of (1) a €300 variable-rate term loan which was drawn on October 25, 2018, and (2) a €300 senior unsecured multicurrency revolving facility agreement. The 2018 UGI International Credit Facilities Agreement matures on October 18, 2023. Term loan borrowings bear interest at rates per annum comprising the aggregate of the applicable margin and the associated euribor rate, which euribor rate has a floor of zero. The margin on term loan borrowings, which ranges from 1.55% to 3.20%, is dependent upon a ratio of net consolidated indebtedness to consolidated EBITDA, as defined. The initial margin on term loan borrowings is 1.70%. UGI International, LLC has entered into pay-fixed, receive-variable interest rate swaps through October 18, 2022, to fix
23
UGI CORPORATION AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Currency in millions, except per share amounts and where indicated otherwise)
the underlying euribor rate on term loan borrowings at 0.34%. Under the multicurrency revolving credit facility agreement, UGI International, LLC may borrow in euros or U.S. dollars. Loans made in euros will bear interest at the associated euribor rate plus a margin ranging from 1.20% to 2.85%. Loans made in U.S. dollars will bear interest at the associated LIBOR rate plus a margin ranging from 1.45% to 3.10%. The margin on revolving facility borrowings is dependent upon a ratio of net consolidated indebtedness to consolidated EBITDA, as defined.
Restrictive covenants under the 2018 UGI International Credit Facilities Agreement include restrictions on the incurrence of additional indebtedness and also restrict liens, guarantees, investments, loans and advances, payments, mergers, consolidations, asset transfers, transactions with affiliates, sales of assets, acquisitions and other transactions. In addition, the 2018 UGI International Credit Facilities Agreement requires a ratio of consolidated total net indebtedness to consolidated EBITDA, as defined, not to exceed 3.85 to 1.00.
On October 25, 2018, UGI International, LLC issued, in an underwritten private placement, €350 principal amount of the UGI International 3.25% Senior Notes due November 1, 2025. The UGI International 3.25% Senior Notes rank equal in right of payment with indebtedness issued under the 2018 UGI International Credit Facilities Agreement.
The net proceeds from the UGI International 3.25% Senior Notes and the 2018 UGI International Credit Facilities Agreement variable-rate term loan plus cash on hand were used on October 25, 2018 (1) to repay €540 outstanding principal of UGI France’s variable-rate term loan under its 2015 senior facilities agreement; €45.8 outstanding principal of Flaga’s variable-rate term loan; and $49.9 outstanding principal of Flaga’s U.S. dollar variable-rate term loan, plus accrued and unpaid interest, and (2) for general corporate purposes. Because these outstanding term loans were refinanced on a long-term basis in October 2018, we have classified €60 of such debt due in April 2019 as long-term debt on the September 30, 2018 Consolidated Balance Sheet. Upon entering into the 2018 UGI International Credit Facilities Agreement, we also terminated (1) UGI International’s existing revolving credit facility agreement dated December 19, 2017, (2) UGI France’s revolving credit facility under its 2015 senior facilities agreement and (3) Flaga’s credit facility agreement. We have designated term loan borrowings under the 2018 UGI International Credit Facilities Agreement and the UGI International 3.25% Senior Notes as net investment hedges.
UGI Utilities Subsequent Event. On February 1, 2019, UGI Utilities issued in a private placement $150 of UGI Utilities 4.55% Senior Notes due February 1, 2049. The UGI Utilities 4.55% Senior Notes were issued pursuant to a Note Purchase Agreement dated December 21, 2018, between UGI Utilities and certain note purchasers. The UGI Utilities 4.55% Senior Notes are unsecured and rank equally with UGI Utilities’ existing outstanding senior debt. The net proceeds from the sale of the UGI Utilities 4.55% Senior Notes were used to reduce short-term borrowings and for general corporate purposes. The UGI Utilities 4.55% Senior Notes include the usual and customary covenants for similar type notes including, among others, maintenance of existence, payment of taxes when due, compliance with laws and maintenance of insurance. The UGI Utilities 4.55% Senior Notes require UGI Utilities not to exceed a ratio of Consolidated Debt to Consolidated Total Capital, as defined, of 0.65 to 1.00.
Note 11 — Commitments and Contingencies
UGI Standby Commitment to Purchase AmeriGas Partners Class B Common Units
On November 7, 2017, UGI entered into a Standby Equity Commitment Agreement with AmeriGas Partners and AmeriGas Propane, Inc. Under the terms of the Commitment Agreement, UGI has committed to make up to $225 of capital contributions to the Partnership through July 1, 2019. UGI’s capital contributions may be made from time to time through July 1, 2019 upon request of the Partnership. There have been no capital contributions made to the Partnership under the Commitment Agreement.
In consideration for any capital contributions made pursuant to the Standby Equity Commitment Agreement, AmeriGas Partners will issue to UGI or a wholly owned subsidiary new Class B Common Units representing limited partner interests in AmeriGas Partners. The Class B Common Units will be issued at a price per unit equal to the 20-day volume-weighted average price of AmeriGas Partners Common Units prior to the date of the Partnership’s related capital call. The Class B Common Units will be entitled to cumulative quarterly distributions at a rate equal to the annualized Common Unit yield at the time of the applicable capital call, plus 130 basis points. The Partnership may choose to make the distributions in cash or in the form of additional Class B Common Units. While outstanding, the Class B Common Units will not be subject to any incentive distributions from the Partnership.
At any time after five years from the initial issuance of the Class B Common Units, holders may elect to convert all or any portion of the Class B Common Units they own into Common Units on a one-for-one basis, and at any time after six years from the initial
24
UGI CORPORATION AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Currency in millions, except per share amounts and where indicated otherwise)
issuance of the Class B Common Units, the Partnership may elect to convert all or any portion of the Class B Common Units into Common Units if (i) the closing trading price of the Common Units is greater than 110% of the applicable purchase price for the Class B Common Units and (ii) the Common Units are listed or admitted for trading on a National Securities Exchange. Upon certain events involving a change of control and immediately prior to a liquidation or winding up of the Partnership, the Class B Common Units will automatically convert into Common Units on a one-for-one basis.
Environmental Matters
UGI Utilities
From the late 1800s through the mid-1900s, UGI Utilities and its current and former subsidiaries owned and operated a number of MGPs prior to the general availability of natural gas. Some constituents of coal tars and other residues of the manufactured gas process are today considered hazardous substances under the Superfund Law and may be present on the sites of former MGPs. Between 1882 and 1953, UGI Utilities owned the stock of subsidiary gas companies in Pennsylvania and elsewhere and also operated the businesses of some gas companies under agreement. By the early 1950s, UGI Utilities divested all of its utility operations other than certain Pennsylvania operations, including those which now constitute UGI South and Electric Utility. Beginning in 2006 and 2008, UGI Utilities also owned and operated two acquired subsidiaries (CPG and PNG), which now constitute UGI North and UGI Central, with similar histories of owning, and in some cases operating, MGPs in Pennsylvania. CPG and PNG merged into UGI Utilities effective October 1, 2018.
Prior to the Utility Merger, each of UGI Utilities and its subsidiaries, CPG and PNG, were subject to COAs with the PADEP to address the remediation of specified former MGP sites in Pennsylvania. In accordance with the COAs, as amended to recognize the Utility Merger, UGI Utilities, as the successor to CPG and PNG, is required to either obtain a certain number of points per calendar year based on defined eligible environmental investigatory and/or remedial activities at the MGPs and in the case of one COA, an additional obligation to plug specific natural gas wells, or make expenditures for such activities in an amount equal to an annual environmental cost cap. The cost cap of the three COAs, in the aggregate, is $5.4. The three COAs are currently scheduled to terminate at the end of 2031, 2020 and 2020. At December 31, 2018, September 30, 2018 and December 31, 2017, our aggregate estimated accrued liabilities for environmental investigation and remediation costs related to the COAs totaled $50.5, $51.0 and $53.4, respectively. UGI Utilities has recorded associated regulatory assets for these costs because recovery of these costs from customers is probable (see Note 8).
We do not expect the costs for investigation and remediation of hazardous substances at Pennsylvania MGP sites to be material to UGI Utilities’ results of operations because UGI Utilities receives ratemaking recovery of actual environmental investigation and remediation costs associated with the sites covered by the COAs. This ratemaking recognition reconciles the accumulated difference between historical costs and rate recoveries with an estimate of future costs associated with the sites.
From time to time, UGI Utilities is notified of sites outside Pennsylvania on which private parties allege MGPs were formerly owned or operated by UGI Utilities or owned or operated by a former subsidiary. Such parties generally investigate the extent of environmental contamination or perform environmental remediation. Management believes that, under applicable law, UGI Utilities should not be liable in those instances in which a former subsidiary owned or operated an MGP. There could be, however, significant future costs of an uncertain amount associated with environmental damage caused by MGPs outside Pennsylvania that UGI Utilities directly operated, or that were owned or operated by a former subsidiary of UGI Utilities if a court were to conclude that (1) the subsidiary’s separate corporate form should be disregarded, or (2) UGI Utilities should be considered to have been an operator because of its conduct with respect to its subsidiary’s MGP. At December 31, 2018, September 30, 2018 and December 31, 2017, neither the undiscounted nor the accrued liability for environmental investigation and cleanup costs for UGI Utilities’ MGP sites outside Pennsylvania was material.
AmeriGas Propane
AmeriGas OLP Saranac Lake. In 2008, the NYDEC notified AmeriGas OLP that the NYDEC had placed property purportedly owned by AmeriGas OLP in Saranac Lake, New York on the New York State Registry of Inactive Hazardous Waste Disposal Sites. A site characterization study performed by the NYDEC disclosed contamination related to a former MGP. AmeriGas OLP responded to the NYDEC in 2009 to dispute the contention it was a PRP as it did not operate the MGP and appeared to only own a portion of the site. In 2017, the NYDEC communicated to AmeriGas OLP that the NYDEC had previously issued three RODs related to remediation of the site totaling approximately $27.7 and requested additional information regarding AmeriGas OLP’s
25
UGI CORPORATION AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Currency in millions, except per share amounts and where indicated otherwise)
purported ownership. AmeriGas renewed its challenge to designation as a PRP and identified potential defenses. The NYDEC subsequently identified a third party PRP with respect to the site.
The NYDEC commenced implementation of the remediation plan in the spring of 2018. Based on our evaluation of the available information, the Partnership accrued an undiscounted environmental remediation liability of $7.5 related to the site during the third quarter of Fiscal 2017. Our share of the actual remediation costs could be significantly more or less than the accrued amount.
Other Matters
Purported Class Action Lawsuits. Between May and October of 2014, purported class action lawsuits were filed in multiple jurisdictions against the Partnership/UGI and a competitor by certain of their direct and indirect customers. The class action lawsuits allege, among other things, that the Partnership and its competitor colluded, beginning in 2008, to reduce the fill level of portable propane cylinders from 17 pounds to 15 pounds and combined to persuade their common customer, Walmart Stores, Inc., to accept that fill reduction, resulting in increased cylinder costs to retailers and end-user customers in violation of federal and certain state antitrust laws. The claims seek treble damages, injunctive relief, attorneys’ fees and costs on behalf of the putative classes.
On October 16, 2014, the United States Judicial Panel on Multidistrict Litigation transferred all of these purported class action cases to the Western Missouri District Court. As the result of rulings on a series of procedural filings, including petitions filed with the Eighth Circuit and the U.S. Supreme Court, both the federal and state law claims of the direct customer plaintiffs and the state law claims of the indirect customer plaintiffs were remanded to the Western Missouri District Court. The decision of the Western Missouri District Court to dismiss the federal antitrust claims of the indirect customer plaintiffs was upheld by the Eighth Circuit. Motions are pending before the Western Missouri District Court regarding the indirect purchasers’ state law claims.
We are unable to reasonably estimate the impact, if any, arising from such litigation. We believe we have strong defenses to the claims and intend to vigorously defend against them.
In addition to the matters described above, there are other pending claims and legal actions arising in the normal course of our businesses. Although we cannot predict the final results of these pending claims and legal actions, we believe, after consultation with counsel, that the final outcome of these matters will not have a material effect on our financial statements.
Note 12 — Defined Benefit Pension and Other Postretirement Plans
The U.S. Pension Plan is a defined benefit pension plan for employees hired prior to January 1, 2009, of UGI, UGI Utilities, PNG, CPG and certain of UGI’s other domestic wholly owned subsidiaries. U.S. Pension Plan benefits are based on years of service, age and employee compensation. We also provide postretirement health care benefits to certain retirees and postretirement life insurance benefits to nearly all U.S. active and retired employees. In addition, employees of UGI France and its subsidiaries are covered by certain defined benefit pension and postretirement plans.
Net periodic pension expense and other postretirement benefit costs include the following components:
Pension Benefits | Other Postretirement Benefits | |||||||||||||||
Three Months Ended December 31, | 2018 | 2017 | 2018 | 2017 | ||||||||||||
Service cost | $ | 2.5 | $ | 2.8 | $ | — | $ | 0.2 | ||||||||
Interest cost | 6.8 | 6.5 | 0.2 | 0.2 | ||||||||||||
Expected return on assets | (9.0 | ) | (8.6 | ) | (0.2 | ) | (0.2 | ) | ||||||||
Amortization of: | ||||||||||||||||
Prior service cost (benefit) | 0.1 | 0.1 | (0.1 | ) | (0.1 | ) | ||||||||||
Actuarial loss | 1.9 | 3.3 | — | 0.1 | ||||||||||||
Net benefit cost (benefit) | 2.3 | 4.1 | (0.1 | ) | 0.2 | |||||||||||
Change in associated regulatory liabilities | — | — | (0.3 | ) | (0.1 | ) | ||||||||||
Net benefit cost (benefit) after change in regulatory liabilities | $ | 2.3 | $ | 4.1 | $ | (0.4 | ) | $ | 0.1 | |||||||
26
UGI CORPORATION AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Currency in millions, except per share amounts and where indicated otherwise)
The U.S. Pension Plan’s assets are held in trust and consist principally of publicly traded, diversified equity and fixed income mutual funds and, to a much lesser extent, UGI Common Stock. It is our general policy to fund amounts for U.S. Pension Plan benefits equal to at least the minimum required contribution set forth in applicable employee benefit laws. During the three months ended December 31, 2018, the Company made no cash contributions to the U.S. Pension Plan. During the three months ended December 31, 2017, the Company made cash contributions to the U.S. Pension Plan of $3.4. The Company expects to make additional cash contributions of approximately $11.5 to the U.S. Pension Plan during the remainder of Fiscal 2019.
UGI Utilities has established a VEBA trust to pay retiree health care and life insurance benefits by depositing into the VEBA the annual amount of postretirement benefits costs, if any. The difference between such cash deposits or expense recorded and the amounts included in UGI Gas’ and Electric Utility’s rates, if any, is deferred for future recovery from, or refund to, ratepayers. There were no required contributions to the VEBA during the three months ended December 31, 2018 and 2017.
We also sponsor unfunded and non-qualified supplemental executive defined benefit retirement plans. Net costs associated with these plans for the three months ended December 31, 2018 and 2017, were not material.
27
UGI CORPORATION AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Currency in millions, except per share amounts and where indicated otherwise)
Note 13 — Fair Value Measurements
Recurring Fair Value Measurements
The following table presents, on a gross basis, our financial assets and liabilities, including both current and noncurrent portions, that are measured at fair value on a recurring basis within the fair value hierarchy, as of December 31, 2018, September 30, 2018 and December 31, 2017:
Asset (Liability) | ||||||||||||||||
Level 1 | Level 2 | Level 3 | Total | |||||||||||||
December 31, 2018: | ||||||||||||||||
Derivative instruments: | ||||||||||||||||
Assets: | ||||||||||||||||
Commodity contracts | $ | 72.1 | $ | 27.9 | $ | — | $ | 100.0 | ||||||||
Foreign currency contracts | $ | — | $ | 24.4 | $ | — | $ | 24.4 | ||||||||
Liabilities: | ||||||||||||||||
Commodity contracts | $ | (35.6 | ) | $ | (78.0 | ) | $ | — | $ | (113.6 | ) | |||||
Foreign currency contracts | $ | — | $ | (8.8 | ) | $ | — | $ | (8.8 | ) | ||||||
Interest rate contracts | $ | — | $ | (3.7 | ) | $ | — | $ | (3.7 | ) | ||||||
Non-qualified supplemental postretirement grantor trust investments (a) | $ | 38.0 | $ | — | $ | — | $ | 38.0 | ||||||||
September 30, 2018: | ||||||||||||||||
Derivative instruments: | ||||||||||||||||
Assets: | ||||||||||||||||
Commodity contracts | $ | 93.5 | $ | 117.5 | $ | — | $ | 211.0 | ||||||||
Foreign currency contracts | $ | — | $ | 20.6 | $ | — | $ | 20.6 | ||||||||
Cross-currency contracts | $ | — | $ | 0.9 | $ | — | $ | 0.9 | ||||||||
Liabilities: | ||||||||||||||||
Commodity contracts | $ | (33.6 | ) | $ | (9.8 | ) | $ | — | $ | (43.4 | ) | |||||
Foreign currency contracts | $ | — | $ | (14.4 | ) | $ | — | $ | (14.4 | ) | ||||||
Interest rate contracts | $ | — | $ | (1.0 | ) | $ | — | $ | (1.0 | ) | ||||||
Non-qualified supplemental postretirement grantor trust investments (a) | $ | 40.8 | $ | — | $ | — | $ | 40.8 | ||||||||
December 31, 2017: | ||||||||||||||||
Derivative instruments: | ||||||||||||||||
Assets: | ||||||||||||||||
Commodity contracts | $ | 47.9 | $ | 71.7 | $ | — | $ | 119.6 | ||||||||
Foreign currency contracts | $ | — | $ | 11.6 | $ | — | $ | 11.6 | ||||||||
Liabilities: | ||||||||||||||||
Commodity contracts | $ | (31.0 | ) | $ | (13.5 | ) | $ | — | $ | (44.5 | ) | |||||
Foreign currency contracts | $ | — | $ | (39.9 | ) | $ | — | $ | (39.9 | ) | ||||||
Interest rate contracts | $ | — | $ | (2.1 | ) | $ | — | $ | (2.1 | ) | ||||||
Cross-currency contracts | $ | — | $ | (0.9 | ) | $ | — | $ | (0.9 | ) | ||||||
Non-qualified supplemental postretirement grantor trust investments (a) | $ | 37.7 | $ | — | $ | — | $ | 37.7 | ||||||||
(a) | Consists primarily of mutual fund investments held in grantor trusts associated with non-qualified supplemental retirement plans (see Note 12.) |
The fair values of our Level 1 exchange-traded commodity futures and option contracts and non-exchange-traded commodity futures and forward contracts are based upon actively quoted market prices for identical assets and liabilities. The remainder of our derivative instruments are designated as Level 2. The fair values of certain non-exchange-traded commodity derivatives designated as Level 2 are based upon indicative price quotations available through brokers, industry price publications or recent
28
UGI CORPORATION AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Currency in millions, except per share amounts and where indicated otherwise)
market transactions and related market indicators. The fair values of our Level 2 interest rate contracts, foreign currency contracts and cross-currency contracts are based upon third-party quotes or indicative values based on recent market transactions. The fair values of investments held in grantor trusts are derived from quoted market prices as substantially all of the investments in these trusts have active markets. There were no transfers between Level 1 and Level 2 during the periods presented.
Other Financial Instruments
The carrying amounts of other financial instruments included in current assets and current liabilities (except for current maturities of long-term debt) approximate their fair values because of their short-term nature. We estimate the fair value of long-term debt by using current market rates and by discounting future cash flows using rates available for similar type debt (Level 2). The carrying amount and estimated fair value of our long-term debt (including current maturities but excluding unamortized debt issuance costs) at December 31, 2018, September 30, 2018 and December 31, 2017 were as follows:
December 31, 2018 | September 30, 2018 | December 31, 2017 | |||||||||
Carrying amount | $ | 4,211.0 | $ | 4,199.4 | $ | 4,319.5 | |||||
Estimated fair value | $ | 3,970.8 | $ | 4,150.3 | $ | 4,430.0 | |||||
Financial instruments other than derivative instruments, such as short-term investments and trade accounts receivable, could expose us to concentrations of credit risk. We limit credit risk from short-term investments by investing only in investment-grade commercial paper, money market mutual funds, securities guaranteed by the U.S. Government or its agencies and FDIC insured bank deposits. The credit risk arising from concentrations of trade accounts receivable is limited because we have a large customer base that extends across many different U.S. markets and a number of foreign countries. For information regarding concentrations of credit risk associated with our derivative instruments, see Note 14. Our investment in a private equity partnership is measured at fair value on a non-recurring basis. Generally this measurement uses Level 3 fair value inputs because the investment does not have a readily available market value.
Note 14 — Derivative Instruments and Hedging Activities
We are exposed to certain market risks related to our ongoing business operations. Management uses derivative financial and commodity instruments, among other things, to manage these risks. The primary risks managed by derivative instruments are (1) commodity price risk; (2) interest rate risk; and (3) foreign currency exchange rate risk. Although we use derivative financial and commodity instruments to reduce market risk associated with forecasted transactions, we do not use derivative financial and commodity instruments for speculative or trading purposes. The use of derivative instruments is controlled by our risk management and credit policies, which govern, among other things, the derivative instruments we can use, counterparty credit limits and contract authorization limits. Although our commodity derivative instruments extend over a number of years, a significant portion of our commodity derivative instruments economically hedge commodity price risk during the next twelve months. For more information on the accounting for our derivative instruments, see Note 2.
Commodity Price Risk
Regulated Utility Operations
Natural Gas
Gas Utility’s tariffs contain clauses that permit recovery of all prudently incurred costs of natural gas it sells to retail core-market customers, including the cost of financial instruments used to hedge purchased gas costs. As permitted and agreed to by the PAPUC pursuant to Gas Utility’s annual PGC filings, Gas Utility currently uses NYMEX natural gas futures and option contracts to reduce commodity price volatility associated with a portion of the natural gas it purchases for its retail core-market customers. Gains and losses on Gas Utility’s natural gas futures contracts and natural gas option contracts are recorded in regulatory assets or liabilities on the Condensed Consolidated Balance Sheets because it is probable such gains or losses will be recoverable from, or refundable to, customers through the PGC recovery mechanism (see Note 8).
29
UGI CORPORATION AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Currency in millions, except per share amounts and where indicated otherwise)
Electricity
Electric Utility’s DS tariffs permit the recovery of all prudently incurred costs of electricity it sells to DS customers, including the cost of financial instruments used to hedge electricity costs. Electric Utility enters into forward electricity purchase contracts to meet a substantial portion of its electricity supply needs. At December 31, 2018, September 30, 2018 and December 31, 2017, all Electric Utility forward electricity purchase contracts were subject to the NPNS exception.
Non-utility Operations
LPG
In order to manage market price risk associated with the Partnership’s fixed-price programs, the Partnership uses over-the-counter derivative commodity instruments, principally price swap contracts. In addition, AmeriGas Partners, certain other domestic businesses and our UGI International operations also use over-the-counter price swap contracts to reduce commodity price volatility associated with a portion of their forecasted LPG purchases. The Partnership, from time to time, enters into price swap agreements to reduce the effects of short-term commodity price volatility. Also, Midstream & Marketing, from time to time, uses NYMEX futures contracts to economically hedge the gross margin associated with the purchase and anticipated later near-term sale of propane.
Natural Gas
In order to manage market price risk relating to fixed-price sales contracts for natural gas, Midstream & Marketing enters into NYMEX and over-the-counter natural gas futures and forward contracts and ICE natural gas basis swap contracts. In addition, Midstream & Marketing uses NYMEX futures contracts to economically hedge the gross margin associated with the purchase and anticipated later near-term sale of natural gas. UGI International also uses natural gas futures and forward contracts to economically hedge market price risk associated with fixed-price sales contracts with its customers.
Electricity
In order to manage market price risk relating to fixed-price sales contracts for electricity, Midstream & Marketing enters into electricity futures and forward contracts. Midstream & Marketing also uses NYMEX and over-the-counter electricity futures contracts to economically hedge the price of a portion of its anticipated future sales of electricity from its electric generation facilities. From time to time, Midstream & Marketing purchases FTRs to economically hedge electricity transmission congestion costs associated with its fixed-price electricity sales contracts and from time to time also enters into NYISO capacity swap contracts to economically hedge the locational basis differences for customers it serves on the NYISO electricity grid. UGI International also uses electricity futures and forward contracts to economically hedge market price risk associated with fixed-price sales and purchase contracts for electricity.
Interest Rate Risk
Prior to their repayment on October 25, 2018 (see Note 10), UGI France’s and Flaga’s long-term debt agreements had interest rates that were generally indexed to short-term market interest rates. UGI France and Flaga entered into pay-fixed, receive-variable interest rate swap agreements to hedge the underlying euribor rates and LIBOR rates of interest on this variable-rate debt. We designated these interest rate swaps as cash flow hedges. These interest rate swaps were settled concurrent with the repayment of the UGI France and Flaga long-term debt. In November 2018, UGI International, LLC entered into pay-fixed, receive-variable interest rate swaps through October 18, 2022, to fix the underlying euribor rate on the 2018 UGI International Credit Facilities Agreement term loan borrowings at 0.34%. We designated these interest rate swaps as cash flow hedges.
UGI Utilities has a variable-rate term loan with an interest rate that is indexed to short-term market interest rates. UGI Utilities has entered into a forward starting, amortizing, pay-fixed, receive-variable interest rate swap agreement commencing September 30, 2019, that generally fixes the underlying variable interest rate on borrowings at 3.00% through July 2022. We have designated this interest rate swap as a cash flow hedge.
The remainder of our businesses’ long-term debt is typically issued at fixed rates of interest. As these long-term debt issues mature, we typically refinance such debt with new debt having interest rates reflecting then-current market conditions. In order to reduce
30
UGI CORPORATION AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Currency in millions, except per share amounts and where indicated otherwise)
market rate risk on the underlying benchmark rate of interest associated with near- to medium-term forecasted issuances of fixed-rate debt, from time to time we enter into IRPAs. We account for IRPAs as cash flow hedges.
At December 31, 2018, September 30, 2018 and December 31, 2017, we had no unsettled IRPAs. At December 31, 2018, the amount of net losses associated with interest rate hedges (excluding pay-fixed, receive-variable interest rate swaps) expected to be reclassified into earnings during the next twelve months is $3.5.
Foreign Currency Exchange Rate Risk
Forward Foreign Currency Exchange Contracts
In order to reduce exposure to foreign exchange rate volatility related to our foreign LPG operations, through September 30, 2016, we entered into forward foreign currency exchange contracts to hedge a portion of anticipated U.S. dollar-denominated LPG product purchases primarily during the heating-season months of October through March. We account for these foreign currency exchange contracts associated with anticipated purchases of U.S. dollar-denominated LPG as cash flow hedges. At December 31, 2018, the amount of net gains associated with these contracts expected to be reclassified into earnings during the next twelve months based upon current fair values is $1.4.
In order to reduce the volatility in net income associated with our foreign operations, principally as a result of changes in the U.S. dollar exchange rate to the euro and British pound sterling, we enter into forward foreign currency exchange contracts. Because these contracts do not qualify for hedge accounting treatment, realized and unrealized gains and losses on these contracts are recorded in “Other non-operating income (expense), net,” on the Condensed Consolidated Statements of Income.
From time to time, we also enter into forward foreign currency exchange contracts to reduce the volatility of the U.S. dollar value of a portion of our UGI International euro-denominated net investments. We account for these foreign currency exchange contracts as net investment hedges. We use the forward rate method for measuring ineffectiveness for these net investment hedges and all changes in the fair value of the forward foreign currency contracts are reported in the cumulative translation adjustment section of AOCI.
Concurrent with the issuance of euro-denominated long-term debt under the 2018 UGI International Credit Facilities Agreement and the UGI International 3.25% Senior Notes in October 2018, we designated this euro-denominated debt as net investment hedges of a portion of our euro-denominated UGI International net investment (see Note 10).
Cross-currency Contracts
Prior to its repayment on October 25, 2018 (see Note 10), Flaga entered into cross-currency swaps to hedge its exposure to the variability in expected future cash flows associated with the foreign currency and interest rate risk of its U.S. dollar denominated variable-rate term loan. These cross-currency hedges included initial and final exchanges of principal from a fixed euro denomination to a fixed U.S. dollar-denominated amount, to be exchanged at a specified rate, which was determined by the market spot rate on the date of issuance. These cross-currency swaps also included interest rate swaps of a floating U.S. dollar-denominated interest rate to a fixed euro-denominated interest rate. We designated these cross-currency swaps as cash flow hedges. These cross-currency swaps were settled concurrent with the repayment of Flaga’s U.S. dollar variable rate term loan in October 2018.
31
UGI CORPORATION AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Currency in millions, except per share amounts and where indicated otherwise)
Quantitative Disclosures Related to Derivative Instruments
The following table summarizes by derivative type the gross notional amounts related to open derivative contracts at December 31, 2018, September 30, 2018 and December 31, 2017, and the final settlement date of the Company's open derivative transactions as of December 31, 2018, excluding those derivatives that qualified for the NPNS exception:
Notional Amounts (in millions) | ||||||||||||||||
Type | Units | Settlements Extending Through | December 31, 2018 | September 30, 2018 | December 31, 2017 | |||||||||||
Commodity Price Risk: | ||||||||||||||||
Regulated Utility Operations | ||||||||||||||||
Gas Utility NYMEX natural gas futures and option contracts | Dekatherms | September 2019 | 14.7 | 23.2 | 13.4 | |||||||||||
FTRs contracts | Kilowatt hours | N/A | — | — | 63.1 | |||||||||||
Non-utility Operations | ||||||||||||||||
LPG swaps | Gallons | January 2021 | 450.4 | 394.3 | 275.4 | |||||||||||
Natural gas futures, forward and pipeline contracts | Dekatherms | October 2023 | 188.0 | 159.7 | 128.3 | |||||||||||
Natural gas basis swap contracts | Dekatherms | March 2023 | 81.2 | 54.4 | 90.2 | |||||||||||
NYMEX natural gas storage | Dekatherms | June 2019 | 0.7 | 1.8 | 1.3 | |||||||||||
NYMEX propane storage | Gallons | April 2019 | 0.3 | 0.6 | 0.1 | |||||||||||
Electricity long forward and futures contracts | Kilowatt hours | May 2022 | 3,974.7 | 4,307.6 | 4,733.9 | |||||||||||
Electricity short forward and futures contracts | Kilowatt hours | May 2022 | 366.7 | 359.3 | 325.2 | |||||||||||
Interest Rate Risk: | ||||||||||||||||
Interest rate swaps | Euro | October 2022 | € | 300.0 | € | 585.8 | € | 645.8 | ||||||||
Interest rate swaps | USD | July 2022 | $ | 114.1 | $ | 114.1 | $ | — | ||||||||
Foreign Currency Exchange Rate Risk: | ||||||||||||||||
Forward foreign currency exchange contracts | USD | September 2021 | $ | 408.6 | $ | 512.2 | $ | 485.7 | ||||||||
Forward foreign currency exchange contracts | Euro | October 2024 | € | 172.8 | € | — | € | — | ||||||||
Cross-currency contracts | USD | N/A | $ | — | $ | 49.9 | $ | 49.9 | ||||||||
Derivative Instrument Credit Risk
We are exposed to risk of loss in the event of nonperformance by our derivative instrument counterparties. Our derivative instrument counterparties principally comprise large energy companies and major U.S. and international financial institutions. We maintain credit policies with regard to our counterparties that we believe reduce overall credit risk. These policies include evaluating and monitoring our counterparties’ financial condition, including their credit ratings, and entering into agreements with counterparties that govern credit limits or entering into netting agreements that allow for offsetting counterparty receivable and payable balances for certain financial transactions, as deemed appropriate. Certain of these agreements call for the posting of collateral by the counterparty or by the Company in the forms of letters of credit, parental guarantees or cash. Additionally, our commodity exchange-traded futures contracts generally require cash deposits in margin accounts. At December 31, 2018, September 30, 2018 and December 31, 2017, restricted cash in brokerage accounts totaled $17.4, $9.6 and $19.8, respectively. Although we have concentrations of credit risk associated with derivative instruments, the maximum amount of loss we would incur if these counterparties failed to perform according to the terms of their contracts, based upon the gross fair values of the derivative
32
UGI CORPORATION AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Currency in millions, except per share amounts and where indicated otherwise)
instruments, was not material at December 31, 2018. Certain of the Partnership’s derivative contracts have credit-risk-related contingent features that may require the posting of additional collateral in the event of a downgrade of the Partnership’s debt rating. At December 31, 2018, if the credit-risk-related contingent features were triggered, the amount of collateral required to be posted would not be material.
Offsetting Derivative Assets and Liabilities
Derivative assets and liabilities are presented net by counterparty on the Condensed Consolidated Balance Sheets if the right of offset exists. We offset amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral against amounts recognized for derivative instruments executed with the same counterparty. Our derivative instruments include both those that are executed on an exchange through brokers and centrally cleared and over-the-counter transactions. Exchange contracts utilize a financial intermediary, exchange or clearinghouse to enter, execute or clear the transactions. Over-the-counter contracts are bilateral contracts that are transacted directly with a third party. Certain over-the-counter and exchange contracts contain contractual rights of offset through master netting arrangements, derivative clearing agreements and contract default provisions. In addition, the contracts are subject to conditional rights of offset through counterparty nonperformance, insolvency or other conditions.
In general, most of our over-the-counter transactions and all exchange contracts are subject to collateral requirements. Types of collateral generally include cash or letters of credit. Cash collateral paid by us to our over-the-counter derivative counterparties, if any, is reflected in the table below to offset derivative liabilities. Cash collateral received by us from our over-the-counter derivative counterparties, if any, is reflected in the table below to offset derivative assets. Certain other accounts receivable and accounts payable balances recognized on the Condensed Consolidated Balance Sheets with our derivative counterparties are not included in the table below but could reduce our net exposure to such counterparties because such balances are subject to master netting or similar arrangements.
33
UGI CORPORATION AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Currency in millions, except per share amounts and where indicated otherwise)
Fair Value of Derivative Instruments
The following table presents the Company’s derivative assets and liabilities by type, as well as the effects of offsetting, as of December 31, 2018, September 30, 2018 and December 31, 2017:
December 31, 2018 | September 30, 2018 | December 31, 2017 | ||||||||||
Derivative assets: | ||||||||||||
Derivatives designated as hedging instruments: | ||||||||||||
Foreign currency contracts | $ | 2.3 | $ | 1.5 | $ | 1.2 | ||||||
Cross-currency contracts | — | 0.9 | — | |||||||||
2.3 | 2.4 | 1.2 | ||||||||||
Derivatives subject to PGC and DS mechanisms: | ||||||||||||
Commodity contracts | 1.3 | 3.0 | 0.4 | |||||||||
Derivatives not designated as hedging instruments: | ||||||||||||
Commodity contracts | 98.7 | 208.0 | 119.2 | |||||||||
Foreign currency contracts | 22.1 | 19.1 | 10.4 | |||||||||
120.8 | 227.1 | 129.6 | ||||||||||
Total derivative assets — gross | 124.4 | 232.5 | 131.2 | |||||||||
Gross amounts offset in the balance sheet | (34.3 | ) | (34.3 | ) | (32.5 | ) | ||||||
Cash collateral received | — | (12.2 | ) | (12.0 | ) | |||||||
Total derivative assets — net | $ | 90.1 | $ | 186.0 | $ | 86.7 | ||||||
Derivative liabilities: | ||||||||||||
Derivatives designated as hedging instruments: | ||||||||||||
Foreign currency contracts | $ | — | $ | (0.4 | ) | $ | (5.6 | ) | ||||
Cross-currency contracts | — | — | (0.9 | ) | ||||||||
Interest rate contracts | (3.7 | ) | (1.0 | ) | (2.1 | ) | ||||||
(3.7 | ) | (1.4 | ) | (8.6 | ) | |||||||
Derivatives subject to PGC and DS mechanisms: | ||||||||||||
Commodity contracts | (0.5 | ) | (0.1 | ) | (2.3 | ) | ||||||
Derivatives not designated as hedging instruments: | ||||||||||||
Commodity contracts | (113.1 | ) | (43.3 | ) | (42.2 | ) | ||||||
Foreign currency contracts | (8.8 | ) | (14.0 | ) | (34.3 | ) | ||||||
(121.9 | ) | (57.3 | ) | (76.5 | ) | |||||||
Total derivative liabilities — gross | (126.1 | ) | (58.8 | ) | (87.4 | ) | ||||||
Gross amounts offset in the balance sheet | 34.3 | 34.3 | 32.5 | |||||||||
Cash collateral pledged | 10.0 | — | — | |||||||||
Total derivative liabilities — net | $ | (81.8 | ) | $ | (24.5 | ) | $ | (54.9 | ) | |||
34
UGI CORPORATION AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Currency in millions, except per share amounts and where indicated otherwise)
Effects of Derivative Instruments
The following tables provide information on the effects of derivative instruments on the Condensed Consolidated Statements of Income and changes in AOCI for the three months ended December 31, 2018 and 2017:
Three Months Ended December 31,: | ||||||||||||||||||
Gain (Loss) Recognized in AOCI | Gain (Loss) Reclassified from AOCI into Income | Location of Gain (Loss) Reclassified from AOCI into Income | ||||||||||||||||
Cash Flow Hedges: | 2018 | 2017 | 2018 | 2017 | ||||||||||||||
Foreign currency contracts | $ | 1.0 | $ | (1.4 | ) | $ | 0.8 | $ | 0.8 | Cost of sales | ||||||||
Cross-currency contracts | (0.1 | ) | 0.1 | (0.3 | ) | 0.2 | Interest expense/other operating income, net | |||||||||||
Interest rate contracts | (2.8 | ) | 0.7 | (1.5 | ) | (0.5 | ) | Interest expense | ||||||||||
Total | $ | (1.9 | ) | $ | (0.6 | ) | $ | (1.0 | ) | $ | 0.5 | |||||||
Net Investment Hedges: | ||||||||||||||||||
Foreign currency contracts | $ | 0.9 | $ | — | ||||||||||||||
Gain (Loss) Recognized in Income | Location of Gain (Loss) Recognized in Income | |||||||||||||||||
Derivatives Not Designated as Hedging Instruments: | 2018 | 2017 | ||||||||||||||||
Commodity contracts | $ | (159.7 | ) | $ | 24.4 | Cost of sales | ||||||||||||
Commodity contracts | (2.8 | ) | (1.3 | ) | Revenues | |||||||||||||
Commodity contracts | (0.4 | ) | 0.1 | Operating and administrative expenses | ||||||||||||||
Foreign currency contracts | 8.9 | (4.8 | ) | Other non-operating income (expense), net | ||||||||||||||
Total | $ | (154.0 | ) | $ | 18.4 | |||||||||||||
For the three months ended December 31, 2018 and 2017, the amounts of derivative gains or losses representing ineffectiveness and the amounts of gains or losses recognized in income as a result of excluding derivatives from ineffectiveness testing were not material.
We are also a party to a number of other contracts that have elements of a derivative instrument. These contracts include, among others, binding purchase orders, contracts that provide for the purchase and delivery, or sale, of energy products, and service contracts that require the counterparty to provide commodity storage, transportation or capacity service to meet our normal sales commitments. Although certain of these contracts have the requisite elements of a derivative instrument, these contracts qualify for NPNS exception accounting because they provide for the delivery of products or services in quantities that are expected to be used in the normal course of operating our business and the price in the contract is based on an underlying that is directly associated with the price of the product or service being purchased or sold.
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UGI CORPORATION AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Currency in millions, except per share amounts and where indicated otherwise)
Note 15 — Accumulated Other Comprehensive Income
The tables below present changes in AOCI, net of tax, during the three months ended December 31, 2018 and 2017:
Three Months Ended December 31, 2018 | Postretirement Benefit Plans | Derivative Instruments | Foreign Currency | Total | ||||||||||||
AOCI — September 30, 2018 | $ | (11.0 | ) | $ | (16.1 | ) | $ | (83.3 | ) | $ | (110.4 | ) | ||||
Other comprehensive loss before reclassification adjustments (after-tax) | — | (1.5 | ) | (15.6 | ) | (17.1 | ) | |||||||||
Amounts reclassified from AOCI: | ||||||||||||||||
Reclassification adjustments (pre-tax) | 0.4 | 1.0 | — | 1.4 | ||||||||||||
Reclassification adjustments tax expense | (0.1 | ) | (0.3 | ) | — | (0.4 | ) | |||||||||
Reclassification adjustments (after-tax) | 0.3 | 0.7 | — | 1.0 | ||||||||||||
Other comprehensive income (loss) attributable to UGI | 0.3 | (0.8 | ) | (15.6 | ) | (16.1 | ) | |||||||||
Reclassification of stranded income tax effects related to TCJA | (2.9 | ) | (3.7 | ) | — | (6.6 | ) | |||||||||
AOCI — December 31, 2018 | $ | (13.6 | ) | $ | (20.6 | ) | $ | (98.9 | ) | $ | (133.1 | ) | ||||
Three Months Ended December 31, 2017 | Postretirement Benefit Plans | Derivative Instruments | Foreign Currency | Total | ||||||||||||
AOCI — September 30, 2017 | $ | (19.2 | ) | $ | (21.4 | ) | $ | (52.8 | ) | $ | (93.4 | ) | ||||
Other comprehensive (loss) income before reclassification adjustments (after-tax) | — | (0.4 | ) | 22.3 | 21.9 | |||||||||||
Amounts reclassified from AOCI: | ||||||||||||||||
Reclassification adjustments (pre-tax) | 0.6 | (0.5 | ) | — | 0.1 | |||||||||||
Reclassification adjustments tax (benefit) expense | (0.2 | ) | 0.1 | — | (0.1 | ) | ||||||||||
Reclassification adjustments (after-tax) | 0.4 | (0.4 | ) | — | — | |||||||||||
Other comprehensive income (loss) attributable to UGI | 0.4 | (0.8 | ) | 22.3 | 21.9 | |||||||||||
AOCI — December 31, 2017 | $ | (18.8 | ) | $ | (22.2 | ) | $ | (30.5 | ) | $ | (71.5 | ) | ||||
For additional information on amounts reclassified from AOCI relating to derivative instruments, see Note 14.
Note 16 — Segment Information
Our operations comprise four reportable segments generally based upon products or services sold, geographic location and regulatory environment: (1) AmeriGas Propane; (2) UGI International; (3) Midstream & Marketing; and (4) UGI Utilities.
Corporate & Other principally comprise net expenses of UGI’s captive general liability insurance company and UGI’s corporate headquarters facility, and UGI’s unallocated corporate and general expenses and interest income. In addition, Corporate & Other includes net gains and losses on commodity and certain foreign currency derivative instruments not associated with current-period transactions (including such amounts attributable to noncontrolling interests) because such items are excluded from profit measures evaluated by our CODM in assessing our reportable segments’ performance or allocating resources. Corporate & Other assets principally comprise cash and cash equivalents of UGI and its captive insurance company, and UGI corporate headquarters’ assets.
The accounting policies of our reportable segments are the same as those described in Note 2, “Summary of Significant Accounting Policies,” in the Company’s 2018 Annual Report. We evaluate AmeriGas Propane’s performance principally based upon Partnership Adjusted EBITDA. Although we use Partnership Adjusted EBITDA to evaluate AmeriGas Propane’s profitability, it should not be considered as an alternative to net income (as an indicator of operating performance) or as an alternative to cash flow (as a measure of liquidity or ability to service debt obligations) and is not a measure of performance or financial condition under GAAP. Our definition of Partnership Adjusted EBITDA may be different from that used by other companies. Our CODM evaluates the performance of our other reportable segments principally based upon their income before income taxes excluding gains and losses
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UGI CORPORATION AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Currency in millions, except per share amounts and where indicated otherwise)
on commodity and certain foreign currency derivative instruments not associated with current-period transactions, as previously mentioned.
Three Months Ended December 31, 2018 | Total | Eliminations | AmeriGas Propane | UGI International | Midstream & Marketing | UGI Utilities | Corporate & Other (b) | |||||||||||||||||||||
Revenues | $ | 2,200.2 | $ | — | $ | 820.2 | $ | 710.7 | $ | 372.5 | $ | 299.1 | $ | (2.3 | ) | |||||||||||||
Intersegment revenues | $ | — | $ | (111.6 | ) | (c) | $ | — | $ | — | $ | 86.9 | $ | 23.6 | $ | 1.1 | ||||||||||||
Cost of sales | $ | 1,425.0 | $ | (110.8 | ) | (c) | $ | 378.5 | $ | 448.6 | $ | 377.5 | $ | 159.5 | $ | 171.7 | ||||||||||||
Segment profit: | ||||||||||||||||||||||||||||
Operating income (loss) | $ | 167.7 | $ | 0.4 | $ | 166.6 | $ | 58.3 | $ | 41.1 | $ | 77.0 | $ | (175.7 | ) | |||||||||||||
Income from equity investees | 1.5 | — | — | — | 1.5 | (d) | — | — | ||||||||||||||||||||
Loss on extinguishments of debt | (6.1 | ) | — | — | (6.1 | ) | — | — | — | |||||||||||||||||||
Other non-operating income (expense), net | 9.0 | — | — | 0.7 | — | 0.4 | 7.9 | |||||||||||||||||||||
Interest expense | (60.2 | ) | — | (42.4 | ) | (5.4 | ) | (0.5 | ) | (11.7 | ) | (0.2 | ) | |||||||||||||||
Income (loss) before income taxes | $ | 111.9 | $ | 0.4 | $ | 124.2 | $ | 47.5 | $ | 42.1 | $ | 65.7 | $ | (168.0 | ) | |||||||||||||
Partnership Adjusted EBITDA (a) | $ | 210.7 | ||||||||||||||||||||||||||
Noncontrolling interests’ net income (loss) | $ | 24.3 | $ | — | $ | 81.5 | $ | 0.1 | $ | — | $ | — | $ | (57.3 | ) | |||||||||||||
Depreciation and amortization | $ | 111.2 | $ | — | $ | 45.7 | $ | 31.4 | $ | 11.5 | $ | 22.5 | $ | 0.1 | ||||||||||||||
Capital expenditures (including the effects of accruals) | $ | 161.8 | $ | — | $ | 31.0 | $ | 27.8 | $ | 25.1 | $ | 77.3 | $ | 0.6 | ||||||||||||||
As of December 31, 2018 | ||||||||||||||||||||||||||||
Total assets | $ | 12,368.3 | $ | (144.3 | ) | $ | 4,020.6 | $ | 3,287.5 | $ | 1,504.9 | $ | 3,424.8 | $ | 274.8 | |||||||||||||
Short-term borrowings | $ | 676.3 | $ | — | $ | 368.5 | $ | 1.8 | $ | 10.0 | $ | 296.0 | $ | — | ||||||||||||||
Goodwill | $ | 3,154.8 | $ | — | $ | 2,003.0 | $ | 951.9 | $ | 17.8 | $ | 182.1 | $ | — | ||||||||||||||
Three Months Ended December 31, 2017 | Total | Eliminations | AmeriGas Propane | UGI International | Midstream & Marketing | UGI Utilities | Corporate & Other (b) | |||||||||||||||||||||
Revenues | $ | 2,125.2 | $ | — | $ | 787.3 | $ | 784.2 | $ | 249.8 | $ | 305.4 | $ | (1.5 | ) | |||||||||||||
Intersegment revenues | $ | — | $ | (97.1 | ) | (c) | $ | — | $ | — | $ | 78.2 | $ | 17.7 | $ | 1.2 | ||||||||||||
Cost of sales | $ | 1,137.4 | $ | (96.0 | ) | (c) | $ | 366.1 | $ | 484.8 | $ | 239.0 | $ | 151.8 | $ | (8.3 | ) | |||||||||||
Segment profit: | ||||||||||||||||||||||||||||
Operating income (e) | $ | 395.0 | $ | 0.2 | $ | 147.9 | $ | 93.2 | $ | 53.4 | $ | 96.9 | $ | 3.4 | ||||||||||||||
Income (loss) from equity investees | 1.0 | — | — | (0.2 | ) | 1.2 | (d) | — | — | |||||||||||||||||||
Other non-operating expense, net (e) | (8.0 | ) | — | — | (4.8 | ) | (1.1 | ) | (0.6 | ) | (1.5 | ) | ||||||||||||||||
Interest expense | (58.2 | ) | — | (40.6 | ) | (5.6 | ) | (0.9 | ) | (10.9 | ) | (0.2 | ) | |||||||||||||||
Income before income taxes | $ | 329.8 | $ | 0.2 | $ | 107.3 | $ | 82.6 | $ | 52.6 | $ | 85.4 | $ | 1.7 | ||||||||||||||
Partnership Adjusted EBITDA (a) | $ | 194.1 | ||||||||||||||||||||||||||
Noncontrolling interests’ net income (loss) | $ | 68.3 | $ | — | $ | 68.0 | $ | (0.3 | ) | $ | — | $ | — | $ | 0.6 | |||||||||||||
Depreciation and amortization | $ | 110.3 | $ | — | $ | 47.4 | $ | 32.2 | $ | 10.1 | $ | 20.4 | $ | 0.2 | ||||||||||||||
Capital expenditures (including the effects of accruals) | $ | 128.5 | $ | — | $ | 23.6 | $ | 21.7 | $ | 11.3 | $ | 71.7 | $ | 0.2 | ||||||||||||||
As of December 31, 2017 | ||||||||||||||||||||||||||||
Total assets | $ | 12,343.9 | $ | (62.6 | ) | $ | 4,206.2 | $ | 3,450.1 | $ | 1,325.1 | $ | 3,174.7 | $ | 250.4 | |||||||||||||
Short-term borrowings | $ | 586.1 | $ | — | $ | 263.5 | $ | 41.1 | $ | 100.0 | $ | 181.5 | $ | — | ||||||||||||||
Goodwill | $ | 3,185.5 | $ | — | $ | 2,001.3 | $ | 990.6 | $ | 11.5 | $ | 182.1 | $ | — | ||||||||||||||
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UGI CORPORATION AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Currency in millions, except per share amounts and where indicated otherwise)
(a)The following table provides a reconciliation of Partnership Adjusted EBITDA to AmeriGas Propane income before income taxes:
Three Months Ended December 31, | ||||||||
2018 | 2017 | |||||||
Partnership Adjusted EBITDA | $ | 210.7 | $ | 194.1 | ||||
Depreciation and amortization | (45.7 | ) | (47.4 | ) | ||||
Interest expense | (42.4 | ) | (40.6 | ) | ||||
Noncontrolling interest (i) | 1.6 | 1.2 | ||||||
Income before income taxes | $ | 124.2 | $ | 107.3 | ||||
(i) | Principally represents the General Partner’s 1.01% interest in AmeriGas OLP. |
(b) | Includes net pre-tax (losses) gains on commodity and certain foreign currency derivative instruments not associated with current-period transactions (including such amounts attributable to noncontrolling interests) totaling $(165.9) and $6.6 during the three months ended December 31, 2018 and 2017, respectively. |
(c) | Represents the elimination of intersegment transactions principally among Midstream & Marketing, UGI Utilities and AmeriGas Propane. |
(d) | Represents AFUDC associated with our PennEast Pipeline equity investment. |
(e) | Amounts reflect the reclassification of non-service income (expense) associated with our pension and other postretirement plans from “Operating and administrative expenses” to “Other non-operating income (expense), net,” on the Condensed Consolidated Statements of Income as a result of the adoption of ASU No. 2017-07 (see Note 3). |
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UGI CORPORATION AND SUBSIDIARIES
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Forward-Looking Statements
Information contained in this Quarterly Report on Form 10-Q may contain forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Exchange Act. Such statements use forward-looking words such as “believe,” “plan,” “anticipate,” “continue,” “estimate,” “expect,” “may,” or other similar words. These statements discuss plans, strategies, events or developments that we expect or anticipate will or may occur in the future.
A forward-looking statement may include a statement of the assumptions or bases underlying the forward-looking statement. We believe that we have chosen these assumptions or bases in good faith and that they are reasonable. However, we caution you that actual results almost always vary from assumed facts or bases, and the differences between actual results and assumed facts or bases can be material, depending on the circumstances. When considering forward-looking statements, you should keep in mind the following important factors that could affect our future results and could cause those results to differ materially from those expressed in our forward-looking statements: (1) adverse weather conditions resulting in reduced demand; (2) cost volatility and availability of propane and other LPG, oil, electricity, and natural gas and the capacity to transport product to our customers; (3) changes in domestic and foreign laws and regulations, including safety, tax, consumer protection, environmental and accounting matters; (4) inability to timely recover costs through utility rate proceedings; (5) the impact of pending and future legal proceedings; (6) competitive pressures from the same and alternative energy sources; (7) failure to acquire new customers and retain current customers thereby reducing or limiting any increase in revenues; (8) liability for environmental claims; (9) increased customer conservation measures due to high energy prices and improvements in energy efficiency and technology resulting in reduced demand; (10) adverse labor relations; (11) customer, counterparty, supplier, or vendor defaults; (12) liability for uninsured claims and for claims in excess of insurance coverage, including those for personal injury and property damage arising from explosions, terrorism, and other catastrophic events that may result from operating hazards and risks incidental to generating and distributing electricity and transporting, storing and distributing natural gas and LPG; (13) transmission or distribution system service interruptions; (14) political, regulatory and economic conditions in the United States and in foreign countries, including the current conflicts in the Middle East, and foreign currency exchange rate fluctuations, particularly the euro; (15) capital market conditions, including reduced access to capital markets and interest rate fluctuations; (16) changes in commodity market prices resulting in significantly higher cash collateral requirements; (17) reduced distributions from subsidiaries impacting the ability to pay dividends; (18) changes in Marcellus Shale gas production; (19) the availability, timing and success of our acquisitions, commercial initiatives and investments to grow our businesses; (20) our ability to successfully integrate acquired businesses and achieve anticipated synergies; (21) the interruption, disruption, failure, malfunction, or breach of our information technology systems, including due to cyber attack; and (22) continued analysis of recent tax legislation.
These factors, and those factors set forth in Item 1A. Risk Factors in the Company’s 2018 Annual Report, are not necessarily all of the important factors that could cause actual results to differ materially from those expressed in any of our forward-looking statements. Other unknown or unpredictable factors could also have material adverse effects on future results. We undertake no obligation to update publicly any forward-looking statement whether as a result of new information or future events except as required by the federal securities laws.
ANALYSIS OF RESULTS OF OPERATIONS
The following analysis compares the Company’s results of operations for the 2018 three-month period with the 2017 three-month period. Our analysis of results of operations should be read in conjunction with the segment information included in Note 16 to the condensed consolidated financial statements.
Because most of our businesses sell or distribute energy products used in large part for heating purposes, our results are significantly influenced by temperatures in our service territories, particularly during the heating-season months of October through March. As a result, our operating results, excluding the effects of gains and losses on commodity derivative instruments not associated with current-period transactions as further discussed below, are significantly higher in our first and second fiscal quarters.
UGI management uses “adjusted net income attributable to UGI Corporation” and “adjusted diluted earnings per share,” both of which are non-GAAP financial measures, when evaluating UGI’s overall performance. Management believes that these non-GAAP measures provide meaningful information to investors. Adjusted net income attributable to UGI Corporation excludes (1) net after-tax gains and losses on commodity and certain foreign currency derivative instruments not associated with current-period transactions and (2) other significant discrete items that management believes affect the comparison of period-over-period results. For further information on these non-GAAP financial measures including reconciliations of such non-GAAP financial measures
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UGI CORPORATION AND SUBSIDIARIES
to the most directly comparable GAAP measures, see “Non-GAAP Financial Measures - Adjusted Net Income Attributable to UGI and Adjusted Earnings Per Diluted Share” below.
Our GAAP net income attributable to UGI Corporation for the three months ended December 31, 2017 was significantly impacted by the TCJA in the U.S. and the December 2017 French Finance Bills in France. Among other things, the TCJA reduces the U.S. federal income tax rate from 35% to 21% effective January 1, 2018, creates a territorial tax system with a one-time mandatory “toll tax” on previously un-repatriated foreign earnings, and allows for immediate capital expensing of certain qualified property which for UGI Utilities and certain FERC-regulated assets is eliminated beginning in Fiscal 2019. For Fiscal 2019, our U.S. federal income tax rate is 21% compared with a blended rate of 24.5% in Fiscal 2018.
As a result of the TCJA and the December 2017 French Finance Bills, during the 2017 three-month period we adjusted our deferred income tax assets and liabilities to remeasure our existing U.S. and French deferred income tax assets and liabilities at the new tax rates in the U.S. and France. Because a significant amount of the reduction related to our regulated utility plant assets, most of the reductions to UGI Utilities’ deferred income tax assets and liabilities were not recognized immediately in income tax expense but were reflected in regulatory assets and liabilities in accordance with utility ratemaking. Although these remeasurement adjustments decreased our income tax expense and increased our GAAP net income in the 2017 three-month period, we eliminated these remeasurement adjustments from our non-GAAP adjusted results presented in the section below entitled “Adjusted Net Income Attributable to UGI Corporation by Business Unit (Non-GAAP).” For further information on the TCJA and the December 2017 French Finance Bills, see Note 6 to Condensed Consolidated Financial Statements.
EXECUTIVE OVERVIEW
THREE MONTHS ENDED DECEMBER 31, 2018 AND 2017
Net Income Attributable to UGI Corporation by Business Unit (GAAP):
Net income attributable to UGI Corporation determined in accordance with GAAP for the three months ended December 31, 2018 and 2017 is as follows:
For the three months ended December 31, | 2018 | 2017 | Variance - Favorable (Unfavorable) | ||||||||||||||||||
(Dollars in millions) | Amount | % of Total | Amount (a) | % of Total | Amount | % Change | |||||||||||||||
AmeriGas Propane | $ | 30.6 | 47.7 | % | $ | 141.6 | 38.7 | % | $ | (111.0 | ) | (78.4 | )% | ||||||||
UGI International (b)(c)(d) | 32.5 | 50.6 | % | 61.1 | 16.7 | % | (28.6 | ) | (46.8 | )% | |||||||||||
Midstream & Marketing | 31.0 | 48.3 | % | 112.0 | 30.6 | % | (81.0 | ) | (72.3 | )% | |||||||||||
UGI Utilities | 49.9 | 77.7 | % | 68.3 | 18.7 | % | (18.4 | ) | (26.9 | )% | |||||||||||
Corporate & Other (e) | (79.8 | ) | (124.3 | )% | (17.1 | ) | (4.7 | )% | (62.7 | ) | N.M. | ||||||||||
Net income attributable to UGI Corporation | $ | 64.2 | 100.0 | % | $ | 365.9 | 100.0 | % | $ | (301.7 | ) | (82.5 | )% | ||||||||
(a) | Net income attributable to UGI Corporation for the three months ended December 31, 2017, includes income (loss) from remeasurement adjustments to tax-related accounts as a result of the enactment of the TCJA as follows: |
AmeriGas Propane | $ | 113.1 | |
UGI International | (9.3 | ) | |
Midstream & Marketing | 74.3 | ||
UGI Utilities | 8.1 | ||
Corporate & Other | (20.2 | ) | |
Net income attributable to UGI Corporation | $ | 166.0 | |
(b) | Three months ended December 31, 2018, includes net after-tax loss from extinguishment of debt of $4.2 million. |
(c) | Three months ended December 31, 2017, includes beneficial impact of a $17.3 million remeasurement adjustment to net deferred income tax liabilities associated with a December 2017 change in French income tax rates. |
(d) | Three months ended December 31, 2017, includes after-tax integration expenses associated with Finagaz of $1.2 million. |
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UGI CORPORATION AND SUBSIDIARIES
(e) | Includes net after-tax (losses) gains on commodity derivative instruments not associated with current-period transactions of $(81.2) million and $4.6 million for the three months ended December 31, 2018 and 2017, respectively. Also includes after-tax unrealized gains (losses) on certain foreign currency derivative instruments of $5.8 million and $(0.1) million for the three months ended December 31, 2018 and 2017, respectively. |
N.M. — Variance is not meaningful.
Adjusted Net Income Attributable to UGI Corporation by Business Unit (Non-GAAP):
Adjusted net income attributable to UGI Corporation for the three months ended December 31, 2018 and 2017 is as follows:
For the three months ended December 31, | 2018 | 2017 | Variance - Favorable (Unfavorable) | ||||||||||||||||||
(Dollars in millions) | Amount | % of Total | Amount | % of Total | Amount | % Change | |||||||||||||||
AmeriGas Propane | $ | 30.6 | 21.3 | % | $ | 28.5 | 15.9 | % | $ | 2.1 | 7.4 | % | |||||||||
UGI International | 36.7 | 25.5 | % | 54.3 | 30.3 | % | (17.6 | ) | (32.4 | )% | |||||||||||
Midstream & Marketing | 31.0 | 21.6 | % | 37.7 | 21.0 | % | (6.7 | ) | (17.8 | )% | |||||||||||
UGI Utilities | 49.9 | 34.7 | % | 60.2 | 33.6 | % | (10.3 | ) | (17.1 | )% | |||||||||||
Corporate & Other | (4.4 | ) | (3.1 | )% | (1.4 | ) | (0.8 | )% | (3.0 | ) | N.M. | ||||||||||
Adjusted net income attributable to UGI Corporation | $ | 143.8 | 100.0 | % | $ | 179.3 | 100.0 | % | $ | (35.5 | ) | (19.8 | )% | ||||||||
N.M. - Variance not meaningful.
Discussion. Adjusted net income attributable to UGI Corporation for the 2018 three-month period was $143.8 million (equal to $0.81 per diluted share) compared to adjusted net income attributable to UGI Corporation for the 2017 three-month period of $179.3 million (equal to $1.01 per diluted share).
Our results for the three months ended December 31, 2018, reflect average temperatures that were significantly warmer than normal and warmer than the prior-year period at our UGI International segment; colder than normal and colder than the prior-year period at our Midstream & Marketing and AmeriGas Propane segments; and approximately normal and slightly colder than the prior-year period at our UGI Utilities segment. Although average temperatures during the 2018 three-month period at our domestic units were colder than the prior-year period, temperatures during the peak heating-season month of December 2018 were much warmer and less volatile than the extremely cold and volatile temperatures experienced during late December 2017.
Adjusted net income attributable to UGI from AmeriGas Propane increased in the 2018 three-month period reflecting higher average retail unit margins and higher retail gallons sold from temperatures that averaged 6.3% colder than the prior-year period. Our UGI International adjusted net income was lower reflecting the negative volume and associated margin effects of significantly warmer weather on heating-related sales, and lower volumes sold for crop drying due to a very dry and warm summer and early fall in Europe. Through December 2018, our UGI International operations had experienced nine consecutive months of warmer-than-normal weather. Midstream & Marketing adjusted net income was also lower than in the 2017 three-month period as results in the prior year benefited from the effects on capacity values of extremely cold late December 2017 weather and, to a lesser extent, due to lower margin from electric generation. Although the weather at UGI Utilities was slightly colder than the prior-year period, UGI Utilities’ 2018 three-month period net income was lower primarily because net income in the prior year included approximately $8.1 million of lower income taxes resulting from the enactment of the TCJA. Although the lower federal tax rates from the TCJA also impacted the 2018 three-month period at UGI Utilities, the tax benefits in the current-year period are being given back to UGI Utilities’ customers through negative surcharge rates in accordance with a May 17, 2018, PAPUC Order. Excluding the $8.1 million tax benefit in the prior-year period, UGI Utilities’ 2018 three-month period adjusted net income was $2.2 million lower than the prior-year period principally reflecting higher operating and administrative expenses and higher depreciation expense.
Non-GAAP Financial Measures - Adjusted Net Income Attributable to UGI and Adjusted Earnings Per Diluted Share
As previously mentioned, UGI management uses “adjusted net income attributable to UGI Corporation” and “adjusted diluted earnings per share,” both of which are non-GAAP financial measures, when evaluating UGI’s overall performance. For the 2018 and 2017 three-month periods, adjusted net income attributable to UGI Corporation is net income attributable to UGI after excluding (1) net after-tax gains and losses on commodity and certain foreign currency derivative instruments not associated with current-period transactions (principally comprising changes in unrealized gains and losses on such derivative instruments); (2) Finagaz integration expenses; (3) losses associated with extinguishments of debt; and (4) one-time impacts on income tax balances resulting from the enactments of the TCJA and French Finance Bills. UGI does not designate its commodity and certain foreign currency derivative instruments as hedges under GAAP. Volatility in net income attributable to UGI Corporation as determined in accordance
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with GAAP can occur as a result of gains and losses on commodity and certain foreign currency derivative instruments not associated with current-period transactions. These gains and losses result principally from recording changes in unrealized gains and losses on unsettled commodity and certain foreign currency derivative instruments and, to a much lesser extent, certain realized gains and losses on settled commodity derivative instruments that are not associated with current-period transactions. However, because these derivative instruments economically hedge anticipated future purchases or sales of energy commodities, or in the case of certain foreign currency derivatives reduce volatility in anticipated future earnings associated with our foreign operations, we expect that such gains or losses will be largely offset by gains or losses on anticipated future energy commodity transactions or mitigate volatility in anticipated future earnings.
Non-GAAP financial measures are not in accordance with, or an alternative to, GAAP and should be considered in addition to, and not as a substitute for, the comparable GAAP measures. Management believes that these non-GAAP measures provide meaningful information to investors about UGI’s performance because they eliminate gains and losses on commodity and certain foreign currency derivative instruments not associated with current-period transactions and other significant discrete items that can affect the comparison of period-over-period results.
The following tables reconcile consolidated net income attributable to UGI Corporation, the most directly comparable GAAP measure, to adjusted net income attributable to UGI Corporation, and reconcile diluted earnings per share, the most comparable GAAP measure, to adjusted diluted earnings per share, to reflect the adjustments referred to above:
Three Months Ended December 31, 2018 | Total | AmeriGas Propane | UGI International | Midstream & Marketing | UGI Utilities | Corporate & Other | ||||||||||||||||||
Adjusted net income attributable to UGI Corporation (millions): | ||||||||||||||||||||||||
Net income (loss) attributable to UGI Corporation | $ | 64.2 | $ | 30.6 | $ | 32.5 | $ | 31.0 | $ | 49.9 | $ | (79.8 | ) | |||||||||||
Net losses on commodity derivative instruments not associated with current-period transactions (net of tax of $(35.5)) (a) | 81.2 | — | — | — | — | 81.2 | ||||||||||||||||||
Unrealized gains on foreign currency derivative instruments (net of tax of $2.3) (a) | (5.8 | ) | — | — | — | — | (5.8 | ) | ||||||||||||||||
Loss on extinguishments of debt (net of tax of $(1.9)) (a) | 4.2 | — | 4.2 | — | — | — | ||||||||||||||||||
Adjusted net income (loss) attributable to UGI Corporation | $ | 143.8 | $ | 30.6 | $ | 36.7 | $ | 31.0 | $ | 49.9 | $ | (4.4 | ) | |||||||||||
Adjusted diluted earnings per share: | ||||||||||||||||||||||||
UGI Corporation earnings (loss) per share — diluted | $ | 0.36 | $ | 0.17 | $ | 0.18 | $ | 0.17 | $ | 0.28 | $ | (0.44 | ) | |||||||||||
Net losses on commodity derivative instruments not associated with current-period transactions (b) | 0.46 | — | — | — | — | 0.46 | ||||||||||||||||||
Unrealized gains on foreign currency derivative instruments | (0.03 | ) | — | — | — | — | (0.03 | ) | ||||||||||||||||
Loss on extinguishments of debt | 0.02 | — | 0.02 | — | — | — | ||||||||||||||||||
Adjusted diluted earnings (loss) per share | $ | 0.81 | $ | 0.17 | $ | 0.20 | $ | 0.17 | $ | 0.28 | $ | (0.01 | ) | |||||||||||
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Three Months Ended December 31, 2017 | Total | AmeriGas Propane | UGI International | Midstream & Marketing | UGI Utilities | Corporate & Other | ||||||||||||||||||
Adjusted net income attributable to UGI Corporation (millions): | ||||||||||||||||||||||||
Net income (loss) attributable to UGI Corporation | $ | 365.9 | $ | 141.6 | $ | 61.1 | $ | 112.0 | $ | 68.3 | $ | (17.1 | ) | |||||||||||
Net gains on commodity derivative instruments not associated with current-period transactions (net of tax of $2.1) (a) | (4.6 | ) | — | — | — | — | (4.6 | ) | ||||||||||||||||
Unrealized losses on foreign currency derivative instruments (net of tax of $(0.0)) (a) | 0.1 | — | — | — | — | 0.1 | ||||||||||||||||||
Integration expenses associated with Finagaz (net of tax of $(0.7)) (a) | 1.2 | — | 1.2 | — | — | — | ||||||||||||||||||
Impact of French Finance Bill | (17.3 | ) | — | (17.3 | ) | — | — | — | ||||||||||||||||
Remeasurement impact of TCJA | (166.0 | ) | (113.1 | ) | 9.3 | (74.3 | ) | (8.1 | ) | 20.2 | ||||||||||||||
Adjusted net income (loss) attributable to UGI Corporation | $ | 179.3 | $ | 28.5 | $ | 54.3 | $ | 37.7 | $ | 60.2 | $ | (1.4 | ) | |||||||||||
Adjusted diluted earnings per share: | ||||||||||||||||||||||||
UGI Corporation earnings (loss) per share - diluted | $ | 2.07 | $ | 0.80 | $ | 0.35 | $ | 0.63 | $ | 0.39 | $ | (0.10 | ) | |||||||||||
Net gains on commodity derivative instruments not associated with current-period transactions | (0.03 | ) | — | — | — | — | (0.03 | ) | ||||||||||||||||
Unrealized losses on foreign currency derivative instruments | — | — | — | — | — | — | ||||||||||||||||||
Integration expenses associated with Finagaz | 0.01 | — | 0.01 | — | — | — | ||||||||||||||||||
Impact of French Finance Bill | (0.10 | ) | — | (0.10 | ) | — | — | — | ||||||||||||||||
Remeasurement impact of TCJA | (0.94 | ) | (0.64 | ) | 0.05 | (0.42 | ) | (0.05 | ) | 0.12 | ||||||||||||||
Adjusted diluted earnings (loss) per share | $ | 1.01 | $ | 0.16 | $ | 0.31 | $ | 0.21 | $ | 0.34 | $ | (0.01 | ) | |||||||||||
(a) | Income taxes associated with pre-tax adjustments determined using statutory business unit tax rates. |
(b) | Includes the effects of rounding associated with per share amounts. |
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SEGMENT RESULTS OF OPERATIONS
2018 Three-Month Period Compared to the 2017 Three-Month Period
AmeriGas Propane
For the three months ended December 31, | 2018 | 2017 | Increase | ||||||||||||
(Dollars in millions) | |||||||||||||||
Revenues | $ | 820.2 | $ | 787.3 | $ | 32.9 | 4.2 | % | |||||||
Total margin (a) | $ | 441.7 | $ | 421.2 | $ | 20.5 | 4.9 | % | |||||||
Partnership operating and administrative expenses | $ | 235.1 | $ | 230.3 | $ | 4.8 | 2.1 | % | |||||||
Partnership Adjusted EBITDA (b) | $ | 210.7 | $ | 194.1 | $ | 16.6 | 8.6 | % | |||||||
Operating income (c) | $ | 166.6 | $ | 147.9 | $ | 18.7 | 12.6 | % | |||||||
Retail gallons sold (millions) | 310.3 | 305.0 | $ | 5.3 | 1.7 | % | |||||||||
Heating degree days—% colder (warmer) than normal (d) | 4.9 | % | (1.4 | )% | — | — | |||||||||
(a) | Total margin represents total revenues less total cost of sales. Total margin for the three months ended December 31, 2018 and 2017 excludes net pre-tax (losses) gains of $(78.5) million and $0.8 million, respectively, on commodity derivative instruments not associated with current-period transactions. |
(b) | Partnership Adjusted EBITDA should not be considered as an alternative to net income (loss) (as an indicator of operating performance) and is not a measure of performance or financial condition under GAAP. Management uses Partnership Adjusted EBITDA as the primary measure of segment profitability for the AmeriGas Propane segment (see Note 16 to Condensed Consolidated Financial Statements). |
(c) | Operating income includes certain operating and administrative expenses of the General Partner. |
(d) | Deviation from average heating degree days for the 15-year period 2002-2016 based upon national weather statistics provided by the NOAA for 344 Geo Regions in the United States, excluding Alaska and Hawaii. |
The Partnership’s retail gallons sold during the 2018 three-month period were 1.7% higher than the prior-year period. Average temperatures based upon heating degree days were 4.9% colder than normal and 6.3% colder than the prior-year period. Average temperatures in the 2017 three-month period were impacted by significantly colder than normal weather in late December.
Retail propane revenues increased $29.1 million during the 2018 three-month period reflecting the effects of higher average retail selling prices ($17.1 million) and the higher retail volumes sold ($12.0 million). Wholesale propane revenues increased $2.3 million reflecting higher wholesale volumes sold ($5.4 million) partially offset by lower average wholesale selling prices ($3.1 million). Average daily wholesale propane commodity prices during the 2018 three-month period at Mont Belvieu, Texas, one of the major supply points in the U.S., were slightly lower than such prices during the 2017 three-month period reflecting lower year-over-year wholesale propane commodity prices later in the 2018 three-month period. Other revenues in the 2018 three-month period were slightly higher than in the prior-year period principally reflecting higher service and ancillary revenues. Total cost of sales increased $12.4 million, principally reflecting the effects of the higher propane volumes sold ($10.9 million).
AmeriGas Propane total margin increased $20.5 million in the 2018 three-month period principally reflecting higher retail propane total margin ($19.5 million) and slightly higher non-propane total margin. The increase in retail propane total margin principally reflects higher average retail propane unit margins due, in part, to the effects of declining wholesale propane prices later during the 2018 three-month period and, to a lesser extent, the higher retail volumes sold.
Partnership Adjusted EBITDA increased $16.6 million in the 2018 three-month period principally reflecting the effects of the higher total margin ($20.5 million) and slightly higher other operating income ($1.1 million), partially offset by a $4.8 million increase in the Partnership operating and administrative expenses. The slight increase in the Partnership operating and administrative expenses includes higher total compensation and benefits costs ($3.1 million), principally higher labor and overtime costs associated with the increased activity, and higher vehicle expenses ($2.2 million). AmeriGas Propane operating income increased $18.7 million in the 2018 three-month period reflecting the $16.6 million increase in Partnership Adjusted EBITDA and, to a much lesser extent, lower depreciation and amortization expense ($1.7 million).
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UGI International
For the three months ended December 31, | 2018 | 2017 | Increase (Decrease) | ||||||||||||
(Dollars in millions) | |||||||||||||||
Revenues | $ | 710.7 | $ | 784.2 | $ | (73.5 | ) | (9.4 | )% | ||||||
Total margin (a) | $ | 262.1 | $ | 299.4 | $ | (37.3 | ) | (12.5 | )% | ||||||
Operating and administrative expenses (b) | $ | 174.4 | $ | 173.7 | $ | 0.7 | 0.4 | % | |||||||
Operating income | $ | 58.3 | $ | 93.2 | $ | (34.9 | ) | (37.4 | )% | ||||||
Income before income taxes (c) | $ | 47.5 | $ | 82.6 | $ | (35.1 | ) | (42.5 | )% | ||||||
LPG retail gallons sold (millions) | 237.6 | 260.6 | $ | (23.0 | ) | (8.8 | )% | ||||||||
UGI International degree days—% (warmer) than normal (d) | (8.0 | )% | (0.7 | )% | — | — | |||||||||
(a) | Total margin represents total revenues less total cost of sales. Total margin for the three months ended December 31, 2018 and 2017 excludes net pre-tax (losses) gains of $(97.3) million and $17.0 million, respectively, on commodity derivative instruments not associated with current-period transactions. |
(b) | The 2017 three-month period includes $1.9 million of Finagaz integration expenses. |
(c) | Income before income taxes for the three months ended December 31, 2018 and 2017 excludes net pre-tax unrealized gains (losses) on certain foreign currency derivative contracts of $8.1 million and $(0.1) million, respectively. Income before income taxes during the three months ended December 31, 2018, is also net of a $6.1 million loss on extinguishments of debt. |
(d) | Deviation from average heating degree days for the 15-year period 2002-2016 at locations in our UGI International service territories. |
Average temperatures during the 2018 three-month period were 8.0% warmer than normal and 7.3% warmer than the prior-year period. Total retail gallons sold during the 2018 three-month period were approximately 9% lower reflecting lower volumes associated with crop drying as a result of a very warm and dry summer, and the effects of the significantly warmer weather on heating-related bulk sales. Through December 2018, UGI International had experienced nine consecutive months of warmer-than-normal weather. Although the average un-weighted wholesale price for LPG for the 2018 three-month period was slightly lower than in the prior-year period, reflecting a significant decline in LPG prices later in the three-month period, wholesale LPG prices during late Fiscal 2018 and early in the 2018 three-month period were significantly higher than in the prior-year period.
UGI International base-currency results are translated into U.S. dollars based upon exchange rates experienced during the reporting periods. The functional currency of a significant portion of our UGI International results is the euro and, to a much lesser extent, the British pound sterling. During the 2018 and 2017 three-month periods, the average unweighted euro-to-dollar translation rates were approximately $1.14 and $1.18, respectively, and the average unweighted British pound sterling-to-dollar translation rates were approximately $1.29 and $1.33, respectively. Although the euro and British pound sterling were slightly weaker during the 2018 three-month period and affect the comparison of line item amounts presented in the table above, the impact of the weaker currencies on net income was substantially offset by net gains on foreign currency exchange contracts.
UGI International revenues decreased $73.5 million during the 2018 three-month period reflecting the effects of the lower volumes sold and, to a much lesser extent, the translation effects of the weaker euro and British pound sterling. UGI International cost of sales decreased $36.2 million during the 2018 three-month period principally reflecting the effects of the lower LPG volumes sold and the translation effects of the slightly lower euro and British pound sterling partially offset by higher average LPG cost of sales reflecting the impact of higher average LPG inventory costs entering the heating season.
UGI International total margin decreased $37.3 million primarily reflecting the lower retail LPG volumes sold and slightly lower LPG unit margins. The lower total margin also reflects, to a lesser extent, the translation effects of the weaker euro and British pound sterling.
The $34.9 million decrease in UGI International operating income principally reflects the previously mentioned $37.3 million decrease in total margin and slightly higher operating and administrative expenses. These decreases to operating income were partially offset by slightly higher other operating income ($2.1 million) and a $0.8 million decrease in depreciation and amortization expense. The slight increase in operating and administrative expenses largely reflects higher compliance costs associated with energy conservation and costs related to strategic projects substantially offset by the translation effects of the weaker euro and British pound sterling and lower cylinder repair costs. Operating and administrative expenses in the prior-year three-month period includes $1.9 million of Finagaz integration costs. The lower depreciation and amortization expense principally reflects the translation effects of the weaker currencies. UGI International income before income taxes in the 2018 three-month period was $35.1 million lower than the prior-year period principally reflecting the net effects of the $34.9 million decrease in UGI International
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operating income and a $6.1 million loss on debt extinguishments partially offset by higher realized gains on foreign currency exchange contracts ($5.4 million).
Midstream & Marketing
For the three months ended December 31, | 2018 | 2017 | Increase (Decrease) | ||||||||||||
(Dollars in millions) | |||||||||||||||
Revenues | $ | 459.4 | $ | 328.0 | $ | 131.4 | 40.1 | % | |||||||
Total margin (a) | $ | 81.9 | $ | 89.0 | $ | (7.1 | ) | (8.0 | )% | ||||||
Operating and administrative expenses | $ | 29.2 | $ | 25.6 | $ | 3.6 | 14.1 | % | |||||||
Operating income | $ | 41.1 | $ | 53.4 | $ | (12.3 | ) | (23.0 | )% | ||||||
Income before income taxes | $ | 42.1 | $ | 52.6 | $ | (10.5 | ) | (20.0 | )% | ||||||
(a) | Total margin represents total revenues less total cost of sales. Total margin for the three months ended December 31, 2018 and 2017 excludes net pre-tax gains (losses) of $1.8 million and $(11.1) million, respectively, on commodity derivative instruments not associated with current-period transactions. |
Average temperatures across Midstream & Marketing’s energy marketing territory during the three months ended December 31, 2018 were approximately 4.1% colder than normal and 5.2% colder than the prior-year period. Although weather for the 2018 three-month period was colder than the prior year, weather in the month of December was approximately 16% warmer than the prior year as the 2017 three-month period experienced extremely cold and more volatile weather in late December.
Midstream & Marketing 2018 three-month period revenues were $131.4 million higher than the prior-year period principally reflecting higher natural gas revenues ($133.8 million) and, to a much lesser extent, higher retail power marketing revenues ($2.4 million). These increases in revenue were partially offset by lower electric generation revenues ($4.6 million) and lower total revenues from midstream assets ($2.9 million). The significant increase in natural gas revenues principally reflects higher average natural gas prices during the 2018 three-month period, the effects of higher natural gas volumes resulting from the colder 2018 three-month period temperatures, and customer growth including customers obtained through Midstream & Marketing’s acquisition of South Jersey Energy Company’s natural gas marketing business. The decrease in revenues from midstream assets principally reflects lower capacity management revenues ($9.1 million) partially offset by higher peaking and natural gas gathering revenues. The decrease in capacity management revenues reflects lower capacity values as the prior-year period benefited from extremely cold weather in late December. Electric generation revenues were lower principally reflecting lower off-peak volumes generated from the Hunlock Station generating facility. Midstream & Marketing cost of sales were $377.5 million in the 2018 three-month period compared to $239.0 million in the 2017 three-month period, an increase of $138.5 million, principally reflecting the higher natural gas costs and higher natural gas volumes.
Midstream & Marketing total margin decreased $7.1 million in the 2018 three-month period principally reflecting lower total margin from our midstream assets ($3.9 million) and lower electric generation total margin ($3.0 million). The decrease in total margin from our midstream assets is principally the result of lower capacity management total margin ($9.1 million) partially offset by higher peaking and natural gas gathering total margin. The lower total margin from electric generation principally reflects lower electric generation volumes principally from our Hunlock Station generating facility reflecting lower off-peak volumes. The decrease in capacity management total margin reflects higher capacity values in the prior-year period resulting in large part from extremely cold and more volatile late December 2017 weather.
Midstream & Marketing operating income and income before income taxes during the 2018 three-month period decreased $12.3 million and $10.5 million, respectively. The decrease in operating income principally reflects the previously mentioned decrease in total margin ($7.1 million), higher operating and administrative expenses ($3.6 million), and higher depreciation expense ($1.4 million). The $3.6 million increase in operating and administrative expenses reflects higher compensation and benefits expense and higher expenses associated with greater peaking, LNG and natural gas gathering activities. The increase in operating and administrative expense also reflects higher operating and maintenance expenses associated with a planned outage at the Conemaugh generating unit. The increase in depreciation expense principally reflects incremental depreciation from the expansion of our LNG and peaking assets. The $10.5 million decrease in income before income taxes in the 2018 three-month period principally reflects the lower operating income ($12.3 million) partially offset by the absence of a pension settlement recorded in the prior-year period and lower interest expense.
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UGI Utilities
For the three months ended December 31, | 2018 | 2017 | Increase (Decrease) | ||||||||||||
(Dollars in millions) | |||||||||||||||
Revenues (a) | $ | 322.7 | $ | 323.1 | $ | (0.4 | ) | (0.1 | )% | ||||||
Total margin (b) | $ | 161.9 | $ | 170.0 | $ | (8.1 | ) | (4.8 | )% | ||||||
Operating and administrative expenses (b) | $ | 61.2 | $ | 52.9 | $ | 8.3 | 15.7 | % | |||||||
Operating income | $ | 77.0 | $ | 96.9 | $ | (19.9 | ) | (20.5 | )% | ||||||
Income before income taxes | $ | 65.7 | $ | 85.4 | $ | (19.7 | ) | (23.1 | )% | ||||||
Gas Utility system throughput—bcf | |||||||||||||||
Core market | 26.5 | 25.5 | 1.0 | 3.9 | % | ||||||||||
Total | 75.7 | 69.2 | 6.5 | 9.4 | % | ||||||||||
Electric Utility distribution sales - gwh | 249.7 | 246.6 | 3.1 | 1.3 | % | ||||||||||
Gas Utility heating degree days—% (warmer) than normal (c) | (0.5 | )% | (1.9 | )% | — | — | |||||||||
(a) | In accordance with the PAPUC Order issued May 17, 2018, Gas Utility’s revenues and total margin for the three months ended December 31, 2018, were reduced by $13.5 million to reflect the give back of tax savings of the TCJA (see Notes 6 and 8 to Condensed Consolidated Financial Statements). |
(b) | Total margin represents total revenues less total cost of sales and revenue-related taxes, i.e., Electric Utility gross receipts taxes, of $1.3 million during each of the three months ended December 31, 2018 and 2017. For financial statement purposes, revenue-related taxes are included in “Operating and administrative expenses” on the Condensed Consolidated Statements of Income (but are excluded from operating expenses presented above). |
(c) | Deviation from average heating degree days for the 15-year period 2000-2014 based upon weather statistics provided by NOAA for airports located within Gas Utility’s service territory. |
Temperatures in Gas Utility’s service territory during the three months ended December 31, 2018, were slightly warmer than normal and 1.5% colder than the three months ended December 31, 2017. Gas Utility core market volumes increased 1.0 bcf (3.9%) principally reflecting the effects of the colder weather and growth in the number of core market customers. Total Gas Utility distribution system throughput increased 6.5 bcf reflecting higher large firm delivery service volumes and the previously mentioned higher core market volumes partially offset by a decrease in interruptible delivery service volumes. Electric Utility kilowatt-hour sales were 1.3% higher than the prior-year period principally reflecting the impact of the colder weather on Electric Utility heating-related sales.
UGI Utilities revenues decreased $0.4 million reflecting a $2.9 million decrease in Gas Utility revenues partially offset by a $2.5 million increase in Electric Utility revenues. In accordance with the May 17, 2018, PAPUC Order, during the three months ended December 31, 2018, Gas Utility’s revenues were reduced by $13.5 million to reflect the give back of tax savings of the TCJA. Excluding the impact of this reduction in revenues, Gas Utility revenues increased $10.6 million principally reflecting an increase in off-system sales revenues including capacity releases ($17.5 million), due in large part to the adoption of ASC 606 (which requires that capacity release contracts be reflected on a gross, rather than net, basis), and higher other revenues ($1.8 million), partially offset by lower core market revenues ($9.9 million). The $9.9 million decrease in Gas Utility core market revenues reflects lower average retail core market PGC rates ($19.0 million) partially offset by the effects of the higher core market throughput ($9.0 million).The increase in Electric Utility revenues during the 2018 three-month period principally reflects higher DS rates ($0.9 million), higher transmission revenue ($0.7 million), and an increase in Electric Utility base rates effective October 27, 2018 ($0.5 million).
UGI Utilities’ cost of sales was $159.5 million in the three months ended December 31, 2018 compared with $151.8 million in the three months ended December 31, 2017, principally reflecting higher Gas Utility cost of sales ($6.3 million) and higher Electric Utility cost of sales ($1.5 million) from the higher DS rates and slightly higher distribution system sales. The higher Gas Utility cost of sales principally reflects higher cost of sales associated with off-system sales including capacity releases ($16.9 million) due in large part to the previously mentioned impact of ASC 606 on the presentation of capacity release contracts, and the effects of higher core market volumes ($4.3 million) partially offset by lower average retail core-market PGC rates ($16.3 million).
UGI Utilities total margin decreased $8.1 million reflecting lower total margin from Gas Utility ($9.1 million) attributable to the impact of the $13.5 million reduction in revenues resulting from the TCJA, partially offset by higher Electric Utility total margin ($1.0 million). Excluding the reduction in Gas Utility total margin resulting from the TCJA, Gas Utility total margin increased $4.4 million principally reflecting higher total margin from Gas Utility core market customers ($2.1 million) and higher other margin ($1.9 million) primarily reflecting the margin impacts of the presentation of certain revenues in accordance with the adoption
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of ASC 606. The increase in Electric Utility margin principally reflects the increase in base rates, higher transmission revenue and, to a lesser extent, the higher distribution volumes sold.
UGI Utilities operating income decreased $19.9 million principally reflecting the decrease in total margin ($8.1 million), higher Gas Utility and Electric Utility operating and administrative expenses ($8.3 million), greater depreciation expense ($2.1 million), and higher other operating expense ($1.2 million). The increase in UGI Utilities operating and administrative expenses principally reflects the absence of a favorable payroll tax adjustment recorded in the prior-year period ($2.1 million) and higher general and administrative costs including an increase in uncollectible accounts expense ($1.6 million), higher IT maintenance and consulting expense ($1.2 million), higher contractor and outside services expense ($1.1 million) and higher compensation and benefits expense ($0.9 million). The increase in depreciation expense reflects increased distribution system and IT capital expenditure activity. UGI Utilities income before income taxes decreased $19.7 million principally reflecting the decrease in UGI Utilities operating income.
Interest Expense and Income Taxes
Our consolidated interest expense during the 2018 three-month period was $60.2 million, slightly higher than the $58.2 million of interest expense recorded during the 2017 three-month period. The higher interest expense principally reflects higher short-term interest expense on credit agreement borrowings.
Our effective income tax rate in the 2018 three-month period reflects a U.S. federal income tax rate of 21%. Our effective income tax rate in the 2017 three-month period reflects a blended U.S. federal income tax rate of 24.5%.
As previously mentioned, our consolidated income taxes for the three months ended December 31, 2017, were significantly impacted by the enactment of the TCJA and the December 2017 French Finance Bills. As a result of the TCJA and the December 2017 French Finance Bills, during the 2017 three-month period we adjusted our deferred income tax assets and liabilities to remeasure our existing U.S. and French deferred income tax assets and liabilities at the new tax rates in the U.S. and France. Due to the effects of utility ratemaking, most of the reductions in UGI Utilities’ deferred income tax assets and liabilities were not recognized immediately in income tax expense but were reflected in regulatory assets and liabilities. Income tax expense for the three months ended December 31, 2017, was reduced by remeasurement adjustments to tax-related accounts as a result of the enactment of the TCJA totaling $166.0 million, and was reduced by remeasurement adjustments to net deferred income tax liabilities as a result of the December 2017 French Finance Bills totaling $17.3 million. For further information on these tax law changes, see Notes 6 and 8 to Condensed Consolidated Financial Statements.
FINANCIAL CONDITION AND LIQUIDITY
We depend on both internal and external sources of liquidity to provide funds for working capital and to fund capital requirements. Our short-term cash requirements not met by cash from operations are generally satisfied with borrowings under credit facilities and, in the case of Midstream & Marketing, also from a Receivables Facility. Long-term cash requirements are generally met through issuance of long-term debt or equity securities. We believe that each of our business units has sufficient liquidity in the forms of cash and cash equivalents on hand; cash expected to be generated from operations; credit facility and Receivable Facility borrowings; and the ability to obtain long-term financing to meet anticipated contractual and projected cash commitments. Issuances of debt and equity securities in the capital markets and additional credit facilities may not, however, be available to us on acceptable terms.
The primary sources of UGI’s cash and cash equivalents are the dividends and other cash payments made to UGI or its corporate subsidiaries by its principal business units. Our cash and cash equivalents totaled $477.6 million at December 31, 2018, compared with $452.6 million at September 30, 2018. Excluding cash and cash equivalents that reside at UGI’s operating subsidiaries, at December 31, 2018 and September 30, 2018, UGI had $218.5 million and $194.3 million of cash and cash equivalents, respectively, most of which are located in the U.S. Such cash is available to pay dividends on UGI Common Stock and for investment purposes.
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Long-term Debt and Short-term Borrowings
Long-term Debt
The Company’s debt outstanding at December 31, 2018 and September 30, 2018, comprises the following:
December 31, 2018 | September 30, 2018 | ||||||||||||||||||||||||||
(Millions of dollars) | AmeriGas Propane | UGI International | Midstream & Marketing | UGI Utilities | Other | Total | Total | ||||||||||||||||||||
Short-term borrowings | $ | 368.5 | $ | 1.8 | $ | 10.0 | $ | 296.0 | $ | — | $ | 676.3 | $ | 424.9 | |||||||||||||
Long-term debt (including current maturities): | |||||||||||||||||||||||||||
Senior notes | $ | 2,575.0 | $ | 401.4 | $ | — | $ | 675.0 | $ | — | $ | 3,651.4 | $ | 3,250.0 | |||||||||||||
Term loans and notes | — | 344.1 | — | 158.8 | — | 502.9 | 890.4 | ||||||||||||||||||||
Other long-term debt | 20.5 | 20.4 | 0.4 | 6.6 | 8.8 | 56.7 | 59.0 | ||||||||||||||||||||
Unamortized debt issuance costs | (26.5 | ) | (9.5 | ) | — | (4.8 | ) | — | (40.8 | ) | (34.1 | ) | |||||||||||||||
Total long-term debt | $ | 2,569.0 | $ | 756.4 | $ | 0.4 | $ | 835.6 | $ | 8.8 | $ | 4,170.2 | $ | 4,165.3 | |||||||||||||
Total debt | $ | 2,937.5 | $ | 758.2 | $ | 10.4 | $ | 1,131.6 | $ | 8.8 | $ | 4,846.5 | $ | 4,590.2 | |||||||||||||
UGI International. On October 18, 2018, UGI International, LLC, a wholly owned second-tier subsidiary of UGI, entered into the 2018 UGI International Credit Facilities Agreement, a five-year unsecured Senior Facilities Agreement with a consortium of banks consisting of (1) a €300 million variable-rate term loan which was drawn on October 25, 2018, and (2) a €300 million senior unsecured multicurrency revolving facility agreement. The 2018 UGI International Credit Facilities Agreement matures on October 18, 2023. Term loan borrowings bear interest at rates per annum comprising the aggregate of the applicable margin and the associated euribor rate, which euribor rate has a floor of zero. The margin on term loan borrowings, which ranges from 1.55% to 3.20%, is dependent upon a ratio of net consolidated indebtedness to consolidated EBITDA, as defined. The initial margin on term loan borrowings is 1.70%. UGI International, LLC has entered into pay-fixed, receive-variable interest rate swaps through October 18, 2022, to fix the underlying euribor rate on term loan borrowings at 0.34%. Under the multicurrency revolving facility agreement, UGI International, LLC may borrow in euros or U.S. dollars. Loans made in euros will bear interest at the associated euribor rate plus a margin ranging from 1.20% to 2.85%. Loans made in U.S. dollars will bear interest at the associated LIBOR rate plus a margin ranging from 1.45% to 3.10%. The margin on revolving facility borrowings is dependent upon a ratio of net consolidated indebtedness to consolidated EBITDA, as defined.
On October 25, 2018, UGI International, LLC issued the UGI International 3.25% Senior Notes, in an underwritten private placement, €350 million principal amount of 3.25% senior unsecured notes due November 1, 2025. The UGI International 3.25% Senior Notes rank equal in right of payment with indebtedness issued under the 2018 UGI International Credit Facilities Agreement.
The net proceeds from the UGI International 3.25% Senior Notes and the UGI International Credit Facilities Agreement variable rate term loan plus cash on hand were used on October 25, 2018 (1) to repay €540 million outstanding principal of UGI France’s variable-rate term loan under its 2015 senior facilities agreement due April 2020; €45.8 million of outstanding principal of Flaga’s variable-rate term loan due October 2020; and $49.9 million of outstanding principal of Flaga’s U.S. dollar variable rate term loan due April 2020, plus accrued and unpaid interest, and (2) for general corporate purposes.
UGI Utilities Subsequent Event. On February 1, 2019, UGI Utilities issued in a private placement $150 million of UGI Utilities 4.55% Senior Notes due February 1, 2049. The UGI Utilities 4.55% Senior Notes were issued pursuant to a Note Purchase Agreement dated December 21, 2018, between UGI Utilities and certain note purchasers. The UGI Utilities 4.55% Senior Notes are unsecured and rank equally with UGI Utilities’ existing outstanding senior debt. The net proceeds from the sale of the UGI Utilities 4.55% Senior Notes were used to reduce short-term borrowings and for general corporate purposes.
For further information on these transactions and the Company’s other long-term borrowings, see Note 10 to Condensed Consolidated Financial Statements.
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Credit Facilities
Additional information related to the Company’s credit agreements can be found in Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and Note 5 to the Consolidated Financial Statements in the Company’s 2018 Annual Report.
Information about the Company’s principal credit agreements (excluding the Energy Services Receivables Facility discussed below) as of December 31, 2018 and 2017, is presented in the table below.
(Currency in millions) | Total Capacity | Borrowings Outstanding | Letters of Credit and Guarantees Outstanding | Available Borrowing Capacity | ||||||||||||
As of December 31, 2018 | ||||||||||||||||
AmeriGas OLP | $ | 600.0 | $ | 368.5 | $ | 63.5 | $ | 168.0 | ||||||||
UGI International, LLC | € | 300.0 | € | — | € | — | € | 300.0 | ||||||||
Energy Services | $ | 240.0 | $ | — | $ | — | $ | 240.0 | ||||||||
UGI Utilities | $ | 450.0 | $ | 296.0 | $ | 2.0 | $ | 152.0 | ||||||||
As of December 31, 2017 | ||||||||||||||||
AmeriGas OLP | $ | 600.0 | $ | 263.5 | $ | 67.2 | $ | 269.3 | ||||||||
UGI International, LLC (a) | € | 300.0 | € | — | € | — | € | 300.0 | ||||||||
UGI France SAS (a) | € | 60.0 | € | — | € | — | € | 60.0 | ||||||||
Flaga (a) | € | 55.0 | € | — | € | 1.0 | € | 54.0 | ||||||||
Energy Services | $ | 240.0 | $ | 55.0 | $ | — | $ | 185.0 | ||||||||
UGI Utilities | $ | 300.0 | $ | 181.5 | $ | 2.0 | $ | 116.5 | ||||||||
(a) | Facility terminated on October 25, 2018, concurrent with entering into the 2018 UGI International Credit Facilities Agreement. |
The average daily and peak short-term borrowings under the Company’s principal credit agreements during the three months ended December 31, 2018 and 2017 are as follows:
For the three months ended December 31, 2018 | For the three months ended December 31, 2017 | |||||||||||||||
(Currency in millions) | Average | Peak | Average | Peak | ||||||||||||
AmeriGas OLP | $ | 306.3 | $ | 401.0 | $ | 199.0 | $ | 286.0 | ||||||||
UGI International, LLC | € | — | € | — | € | — | € | — | ||||||||
Energy Services | $ | — | $ | — | $ | 44.7 | $ | 79.0 | ||||||||
UGI Utilities | $ | 250.7 | $ | 311.0 | $ | 168.1 | $ | 205.0 | ||||||||
UGI International. On October 18, 2018, UGI International, LLC entered into a €300 million senior unsecured multicurrency revolving credit facility agreement. For further information on this transaction, see “Long-term Debt” above.
Midstream & Marketing. Energy Services has a Receivables Facility with an issuer of receivables-backed commercial paper currently scheduled to expire on October 25, 2019. At December 31, 2018, the outstanding balance of ESFC trade receivables was $135.4 million, of which $10.0 million were sold to the bank. At December 31, 2017, the outstanding balance of ESFC trade receivables was $101.0 million, of which $45.0 million was sold to the bank. Amounts sold to the bank are reflected as “Short-term borrowings” on the Condensed Consolidated Balance Sheets. During the three months ended December 31, 2018 and 2017, peak sales of receivables were $15.0 million and $45.0 million, respectively, and average daily amounts sold were $1.5 million and $28.6 million, respectively. For additional information regarding the Receivables Facility, see Note 9 to the Condensed Consolidated Financial Statements.
UGI Standby Commitment to Purchase AmeriGas Partners Class B Common Units
AmeriGas Partners has a Standby Equity Commitment Agreement with the General Partner and UGI under which UGI has committed to make up to $225 million of capital contributions to the Partnership through July 1, 2019. UGI’s capital contributions may be made from time to time through July 1, 2019, upon request of the Partnership. In consideration for any capital contributions pursuant to the Standby Equity Commitment Agreement, the Partnership will issue to UGI or a wholly owned subsidiary new
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AmeriGas Partners Class B Common Units representing limited partner interests in the Partnership. There have been no capital contributions made to the Partnership under the Standby Equity Commitment Agreement.
Dividends and Distributions
On November 16, 2018, UGI’s Board of Directors declared a cash dividend equal to $0.26 per common share. The dividend was paid on January 1, 2019, to shareholders of record on December 14, 2018. On January 30, 2019, UGI’s Board of Directors declared a quarterly dividend of $0.26 per common share. The dividend is payable April 1, 2019, to shareholders of record on March 15, 2019.
During the three months ended December 31, 2018, the General Partner’s Board of Directors declared and the Partnership paid a quarterly distribution on all limited partner units at a rate of $0.95 per Common Unit for the quarter ended September 30, 2018. On January 29, 2019, the General Partner’s Board of Directors approved a quarterly distribution of $0.95 per limited partner unit for the quarter ended December 31, 2018. The distribution will be paid on February 19, 2019, to unitholders of record on February 11, 2019.
Cash Flows
Due to the seasonal nature of the Company’s businesses, cash flows from operating activities are generally strongest during the second and third fiscal quarters when customers pay for natural gas, LPG, electricity and other energy products and services consumed during the peak heating season months. Conversely, operating cash flows are generally at their lowest levels during the fourth and first fiscal quarters when the Company’s investment in working capital, principally inventories and accounts receivable, is generally greatest.
Operating Activities. Cash flow provided by operating activities was $96.6 million in the 2018 three-month period compared to $31.4 million in the 2017 three-month period. Cash flow from operating activities before changes in operating working capital was $372.2 million in the 2018 three-month period compared to $380.9 million in the prior-year period. The lower cash flow from operating activities before changes in operating working capital principally reflects the lower operating results in the current-year period. Cash used to fund changes in operating working capital totaled $275.6 million in the 2018 three-month period compared to $349.5 million in the prior-year period. The lower net cash used in the 2018 three-month period reflects, among other things, higher cash receipts from customers due to timing of sales. Sales and associated revenues occurred earlier in the 2018 three-month period compared with sales and associated revenues that occurred later in the 2017 three-month period as the prior-year period experienced extreme cold weather in late December 2017. The greater cash received from changes in inventory principally reflects the impacts of lower and declining propane product costs at AmeriGas Propane during the 2018 three-month period compared to more moderate cash flow effects of higher and more stable propane product costs experienced in the prior-year period. These increases in cash flow from changes in operating working capital were partially offset by, among other things, net refunds of utility PGC costs during the current-year period compared to net recoveries of such costs during the prior-year period, and commodity derivative instrument collateral deposits paid in the current-year three-month period compared to collateral deposits received in the prior-year period.
Investing Activities. Cash flow used by investing activities was $194.0 million in the 2018 three-month period compared with $318.0 million in the prior-year period. Investing activity cash flow is principally affected by expenditures for property, plant and equipment; cash paid for acquisitions of businesses and assets; investments in investees; and proceeds from sales of assets and businesses. Cash payments for property, plant and equipment were $183.3 million in the 2018 three-month period compared to $147.5 million in the prior-year period reflecting, in part, higher IT expenditures associated with Enterprise Resource Planning systems and slightly higher UGI Utilities main replacement and new business capital expenditures. Cash used for acquisitions of businesses and assets in the 2018 three-month period reflects Energy Services’ acquisition of South Jersey Energy Company’s natural gas marketing business located in the Mid-Atlantic region. Cash used for acquisitions of businesses and assets in the 2017 three-month period principally reflects UGI International’s acquisition of UniverGas and Midstream & Marketing’s acquisition of the Texas Creek natural gas gathering assets.
Financing Activities. Cash flow provided by financing activities was $134.0 million in the 2018 three-month period compared with $181.1 million in the prior-year period. Changes in cash flow from financing activities are primarily due to issuances and repayments of long-term debt; net short-term borrowings; dividends and distributions on UGI Common Stock and AmeriGas Partners Common Units; and, from time to time, issuances of UGI and AmeriGas Partners equity instruments. On October 25, 2018, UGI International, LLC, pursuant to a new five-year unsecured Senior Facilities Agreement, borrowed €300 million under a variable-rate term loan facility. Also on October 25, 2018, UGI International, LLC issued in an underwritten private placement €350 million principal amount of 3.25% senior unsecured notes due November 1, 2025. The net proceeds from these borrowings plus cash on hand were used principally to repay €540 million outstanding principal of UGI France SAS’s variable-rate term loan;
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€45.8 million of outstanding principal of Flaga’s variable-rate term loan; and $49.9 million of outstanding principal of Flaga’s U.S. dollar variable-rate term loan, plus accrued and unpaid interest.
UTILITY REGULATORY MATTERS
Utility Merger. On March 8, 2018 and March 13, 2018, UGI Utilities filed merger authorization requests with the PAPUC and MDPSC, respectively, to merge PNG and CPG into UGI Utilities, with a targeted effective date of October 1, 2018. After receiving all necessary FERC, MDPSC, and PAPUC approvals, CPG and PNG were merged into UGI Utilities effective October 1, 2018. Consistent with the MDPSC order issued July 25, 2018, and the PAPUC order issued September, 26, 2018, the former CPG, PNG and UGI Utilities, Inc. Gas Division service territories became the UGI Central, UGI North and UGI South rate districts of the UGI Utilities, Inc. Gas Division, respectively, without any ratemaking change. UGI Utilities’ obligations under the settlement approved by the PAPUC include various non-monetary conditions requiring UGI Utilities to maintain separate accounting-type schedules for limited future ratemaking purposes.
Base Rate Filings. On January 28, 2019, UGI Gas filed a request with the PAPUC to increase its operating revenues for residential, commercial and industrial customers by $71.1 million annually. The requested rate increase applies to the consolidated UGI Central, UGI North and UGI South rate districts. The increased revenues would fund ongoing system improvements and operations necessary to maintain safe and reliable natural gas service and fund new programs designed to promote and reward customers’ efforts to increase efficient use of natural gas. Additionally, UGI Gas has proposed a 4.5% negative surcharge applicable to all customer distribution service bills to return $26.2 million of tax benefits experienced by UGI Utilities over the period January 1, 2018 to June 30, 2018, inclusive of interest. As proposed, the negative surcharge will become effective for a twelve-month period beginning on the effective date of the new base rates. UGI Gas is requesting that the new gas rates become effective March 29, 2019. However, the PAPUC typically suspends the effective date for general base rate proceedings for a period not to exceed nine months after the filing date to allow for investigation and public hearings. UGI Utilities cannot predict the timing or the ultimate outcome of the rate case review process.
On January 26, 2018, Electric Utility filed a rate request with the PAPUC to increase its annual base distribution revenues by $9.2 million, which was later reduced by Electric Utility to $7.7 million to reflect the impact of the TCJA and other adjustments. The increased revenues would fund ongoing system improvements and operations necessary to maintain safe and reliable electric service. On October 25, 2018, the PAPUC approved a final order providing for a $3.2 million annual base distribution rate increase for Electric Utility, effective October 27, 2018. As part of the final order, Electric Utility provided customers with a one-time $0.2 million billing credit associated with 2018 TCJA tax benefits. On November 26, 2018, the Pennsylvania Office of Consumer Advocate filed an appeal to the Pennsylvania Commonwealth Court challenging the PAPUC’s acceptance of UGI Utilities’ use of a fully projected future test year and handling of consolidated federal income tax benefits. UGI Utilities cannot predict the ultimate outcome of this appeal.
Manor Township, Pennsylvania Natural Gas Incident Complaint. In connection with a July 2, 2017, explosion in Manor Township, Lancaster County, Pennsylvania, that resulted in the death of one UGI Utilities’ employee and injuries to two UGI Utilities’ employees and one sewer authority employee, and destroyed two residences and damaged several other homes, the BIE filed a formal complaint at the PAPUC in which BIE alleged that UGI Utilities committed multiple violations of federal and state gas pipeline regulations in connection with its emergency response leading up to the explosion, and it requested that the PAPUC order UGI Utilities to pay approximately $2.1 million in civil penalties, which is the maximum allowable fine. On November 16, 2018, UGI Utilities filed its formal written answer contesting the BIE complaint. The matter remains pending before the PAPUC.
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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Our primary market risk exposures are (1) commodity price risk; (2) interest rate risk; and (3) foreign currency exchange rate risk. Although we use derivative financial and commodity instruments to reduce market price risk associated with forecasted transactions, we do not use derivative financial and commodity instruments for speculative or trading purposes.
Commodity Price Risk
The risk associated with fluctuations in the prices the Partnership and our UGI International operations pay for LPG is principally a result of market forces reflecting changes in supply and demand for LPG and other energy commodities. Their profitability is sensitive to changes in LPG supply costs. Increases in supply costs are generally passed on to customers. The Partnership and UGI International may not, however, always be able to pass through product cost increases fully or on a timely basis, particularly when product costs rise rapidly. In order to reduce the volatility of LPG market price risk, the Partnership uses contracts for the forward purchase or sale of propane, propane fixed-price supply agreements and over-the-counter derivative commodity instruments including price swap contracts. Our UGI International operations use over-the-counter derivative commodity instruments and may from time to time enter into other derivative contracts, similar to those used by the Partnership, to reduce market risk associated with a portion of their LPG purchases. Over-the-counter derivative commodity instruments used to economically hedge forecasted purchases of LPG are generally settled at expiration of the contract. In addition, certain of our UGI International businesses hedge a portion of their anticipated U.S. dollar-denominated LPG product purchases through the use of forward foreign currency exchange contracts as further described below.
Gas Utility's tariffs contain clauses that permit recovery of all prudently incurred costs of natural gas it sells to its retail core-market customers, including the cost of financial instruments used to hedge purchased gas costs. The recovery clauses provide for periodic adjustments for the difference between the total amounts actually collected from customers through PGC rates and the recoverable costs incurred. Because of this ratemaking mechanism, there is limited commodity price risk associated with our Gas Utility operations. Gas Utility uses derivative financial instruments, including natural gas futures and option contracts traded on the NYMEX, to reduce volatility in the cost of gas it purchases for its retail core-market customers. The cost of these derivative financial instruments, net of any associated gains or losses, is included in Gas Utility's PGC recovery mechanism. At December 31, 2018, the fair values of Gas Utility’s natural gas futures and option contracts were not material.
Electric Utility's DS tariffs contain clauses which permit recovery of all prudently incurred power costs, including the cost of financial instruments used to hedge electricity costs, through the application of DS rates. Because of this ratemaking mechanism, there is limited power cost risk, including the cost of forward electricity purchase contracts, associated with our Electric Utility operations. At December 31, 2018, all of Electric Utility’s forward electricity purchase contracts were subject to the NPNS exception.
In addition, Gas Utility and Electric Utility from time to time enter into exchange-traded gasoline futures contracts for a portion of gasoline volumes expected to be used in their operations. These gasoline futures contracts are recorded at fair value with changes in fair value reflected in “Operating and administrative expenses” on the Condensed Consolidated Statements of Income. At December 31, 2018, the fair values of Gas Utility’s and Electric Utility’s gasoline futures contracts were not material.
In order to manage market price risk relating to substantially all of Midstream & Marketing’s fixed-price sales contracts for natural gas and electricity, Midstream & Marketing enters into NYMEX, ICE and over-the-counter natural gas and electricity futures and natural gas basis swap contracts or enters into fixed-price supply arrangements. Midstream & Marketing also uses NYMEX and over-the-counter electricity futures contracts to economically hedge a portion of its anticipated sales of electricity from its electricity generation facilities. Although Midstream & Marketing’s fixed-price supply arrangements mitigate most risks associated with its fixed-price sales contracts, should any of the suppliers under these arrangements fail to perform, increases, if any, in the cost of replacement natural gas or electricity would adversely impact Midstream & Marketing’s results. In order to reduce this risk of supplier nonperformance, Midstream & Marketing has diversified its purchases across a number of suppliers. UGI International’s natural gas and electricity marketing businesses also use natural gas and electricity futures and forward contracts to economically hedge market risk associated with fixed-price sales and purchase contracts.
From time to time, Midstream & Marketing purchases FTRs to economically hedge certain transmission costs that may be associated with its fixed-price electricity sales contracts. Midstream & Marketing from time to time also enters into NYISO capacity swap contracts to economically hedge the locational basis differences for customers it serves on the NYISO electricity grid. Midstream & Marketing also uses NYMEX futures contracts to economically hedge the gross margin associated with the purchase and anticipated later near-term sale of natural gas or propane.
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Midstream & Marketing has entered into fixed-price sales agreements for a portion of the electricity expected to be generated by its electric generation assets. In the event that these generation assets would not be able to produce all of the electricity needed to supply electricity under these agreements, Midstream & Marketing would be required to purchase electricity on the spot market or under contract with other electricity suppliers. Accordingly, increases in the cost of replacement power could negatively impact Midstream & Marketing’s results.
The fair value of unsettled commodity price risk sensitive derivative instruments held at December 31, 2018 (excluding those Gas Utility and Electric Utility commodity derivative instruments that are refundable to, or recoverable from, customers) was a loss of $14.4 million. A hypothetical 10% adverse change in the market price of LPG, gasoline, natural gas and electricity would result in a decrease in fair value of approximately $91.2 million at December 31, 2018.
Interest Rate Risk
We have both fixed-rate and variable-rate debt. Changes in interest rates impact the cash flows of variable-rate debt but generally do not impact their fair value. Conversely, changes in interest rates impact the fair value of fixed-rate debt but do not impact their cash flows.
Our variable-rate debt at December 31, 2018, includes short-term borrowings and UGI International’s and UGI Utilities’ variable-rate term loans. These debt agreements have interest rates that are generally indexed to short-term market interest rates. UGI International has entered into pay-fixed, receive-variable interest rate swaps that generally fixes the underlying euribor interest rate on its euro-denominated term loan at 0.34% through October 2022. UGI Utilities has entered into a forward starting, amortizing, pay-fixed, receive-variable interest rate swap that generally fixes the underlying prevailing market interest rates on its variable-rate term loan at 3.00% beginning September 30, 2019 through July 2022. We have designated this forward-starting interest rate swap as a cash flow hedge. At December 31, 2018, combined borrowings outstanding under variable-rate debt agreements, excluding UGI International’s effectively fixed-rate debt, totaled $795.1 million.
Long-term debt associated with our domestic businesses is typically issued at fixed rates of interest based upon market rates for debt with similar terms and credit ratings. As these long-term debt issues mature, we may refinance such debt with new debt having interest rates reflecting then-current market conditions. In order to reduce interest rate risk associated with near- to medium-term forecasted issuances of fixed rate debt, from time to time we enter into IRPAs.
The fair value of unsettled interest rate risk sensitive derivative instruments held at December 31, 2018 (including pay-fixed, receive-variable interest rate swaps) was a loss of $3.7 million. A 50 basis point adverse change in short-term market interest rates would result in a decrease in fair value of approximately $3.2 million.
Foreign Currency Exchange Rate Risk
Our primary currency exchange rate risk is associated with the U.S. dollar versus the euro and, to a lesser extent, the U.S. dollar versus the British pound sterling. The U.S. dollar value of our foreign currency denominated assets and liabilities will fluctuate with changes in the associated foreign currency exchange rates. From time to time, we use derivative instruments to hedge portions of our net investments in foreign subsidiaries. Gains or losses on these net investment hedges remain in AOCI until such foreign operations are sold or liquidated. With respect to our net investments in our UGI International operations, a 10% decline in the value of the associated foreign currencies versus the U.S. dollar would reduce their aggregate net book value at December 31, 2018, by approximately $110 million, which amount would be reflected in other comprehensive income. In October 2018, concurrent with entering into the 2018 UGI International Credit Facilities Agreement and the UGI International 3.25% Senior Notes, we designated borrowings under these agreements as net investment hedges.
In addition, in order to reduce exposure to foreign exchange rate volatility related to our foreign LPG operations, through September 30, 2016, we entered into forward foreign currency exchange contracts to hedge a portion of anticipated U.S. dollar-denominated LPG product purchases primarily during the heating-season months of October through March.
In order to reduce the volatility in net income associated with our foreign operations, principally as a result of changes in the U.S. dollar exchange rate between the euro and British pound sterling, we enter into forward foreign currency exchange contracts.
The fair value of unsettled foreign currency exchange rate risk sensitive derivative instruments held at December 31, 2018, was a gain of $15.6 million. A hypothetical 10% adverse change in the value of the euro and the British pound sterling versus the U.S. dollar would result in a decrease in fair value of approximately $39.4 million.
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Derivative Instrument Credit Risk
We are exposed to risk of loss in the event of nonperformance by our derivative instrument counterparties. Our derivative instrument counterparties principally comprise large energy companies and major U.S. and international financial institutions. We maintain credit policies with regard to our counterparties that we believe reduce overall credit risk. These policies include evaluating and monitoring our counterparties’ financial condition, including their credit ratings, and entering into agreements with counterparties that govern credit limits or entering into netting agreements that allow for offsetting counterparty receivable and payable balances for certain financial transactions, as deemed appropriate.
Certain of these derivative instrument agreements call for the posting of collateral by the counterparty or by the Company in the forms of letters of credit, parental guarantees or cash. Additionally, our commodity exchange-traded futures contracts generally require cash deposits in margin accounts. At December 31, 2018, restricted cash in brokerage accounts totaled $17.4 million. Although we have concentrations of credit risk associated with derivative instruments, the maximum amount of loss, based upon the gross fair values of the derivative instruments, we would incur if these counterparties failed to perform according to the terms of their contracts was not material at December 31, 2018. Certain of the Partnership’s derivative contracts have credit-risk-related contingent features that may require the posting of additional collateral in the event of a downgrade of the Partnership’s debt rating. At December 31, 2018, if the credit-risk-related contingent features were triggered, the amount of collateral required to be posted would not be material.
ITEM 4. CONTROLS AND PROCEDURES
(a) | Evaluation of Disclosure Controls and Procedures |
The Company's disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by the Company in reports filed or submitted under the Securities Exchange Act of 1934, as amended, is (i) recorded, processed, summarized, and reported within the time periods specified in the SEC’s rules and forms, and (ii) accumulated and communicated to our management, including the Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure. The Company's management, with the participation of the Company’s Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of the Company's disclosure controls and procedures as of the end of the period covered by this report. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Company's disclosure controls and procedures, as of the end of the period covered by this Report, were effective at the reasonable assurance level.
(b) | Change in Internal Control over Financial Reporting |
No change in the Company’s internal control over financial reporting occurred during the Company’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.
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PART II OTHER INFORMATION
ITEM 1A. RISK FACTORS
In addition to the information presented in this report, you should carefully consider the factors discussed in Part I, “Item 1A. Risk Factors” in our 2018 Annual Report, which could materially affect our business, financial condition or future results. The risks described in our 2018 Annual Report are not the only risks facing the Company. Other unknown or unpredictable factors could also have material adverse effects on future results.
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
The following table sets forth information with respect to the Company’s repurchases of its common stock during the quarter ended December 31, 2018.
Period | (a) Total Number of Shares Purchased | (b) Average Price Paid per Share (or Unit) | (c) Total Number of Shares (or Units) Purchased as Part of Publicly Announced Plans or Programs (1) | (d) Maximum Number (or Approximate Dollar Value) of Shares (or Units) that May Yet Be Purchased Under the Plans or Programs (1) | ||||
October 1, 2018 to October 31, 2018 | — | $0.00 | — | 7.10 million | ||||
November 1, 2018 to November 30, 2018 | — | $0.00 | — | 7.10 million | ||||
December 1, 2018 to December 31, 2018 | 300,000 | $56.15 | 300,000 | 6.80 million | ||||
Total | 300,000 | 300,000 | ||||||
(1) | Shares of UGI Corporation Common Stock are repurchased through an extension of a previous share repurchase program announced by the Company on January 25, 2018. The UGI Board of Directors authorized the repurchase of up to 8 million shares of UGI Corporation Common Stock over a four-year period expiring in January 2022. |
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ITEM 6. EXHIBITS
The exhibits filed as part of this report are as follows (exhibits incorporated by reference are set forth with the name of the registrant, the type of report and last date of the period for which it was filed, and the exhibit number in such filing):
Incorporation by Reference
Exhibit No. | Exhibit | Registrant | Filing | Exhibit | ||||
4.1 | Utilities | Form 8-K (12/21/18) | 4.1 | |||||
4.2 | UGI | Form 8-K (10/25/18) | 4.1 | |||||
4.3 | UGI | Form 8-K (10/25/18) | 4.2 | |||||
10.1 | ||||||||
10.2 | UGI | Form 8-K (10/26/18) | 10.1 | |||||
31.1 | ||||||||
31.2 | ||||||||
32 | ||||||||
101.INS | XBRL Instance | |||||||
101.SCH | XBRL Taxonomy Extension Schema | |||||||
101.CAL | XBRL Taxonomy Extension Calculation Linkbase | |||||||
101.DEF | XBRL Taxonomy Extension Definition Linkbase | |||||||
101.LAB | XBRL Taxonomy Extension Labels Linkbase | |||||||
101.PRE | XBRL Taxonomy Extension Presentation Linkbase | |||||||
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EXHIBIT INDEX
10.1 | ||
31.1 | ||
31.2 | ||
32 | ||
101.INS | XBRL Instance | |
101.SCH | XBRL Taxonomy Extension Schema | |
101.CAL | XBRL Taxonomy Extension Calculation Linkbase | |
101.DEF | XBRL Taxonomy Extension Definition Linkbase | |
101.LAB | XBRL Taxonomy Extension Labels Linkbase | |
101.PRE | XBRL Taxonomy Extension Presentation Linkbase | |
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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
UGI Corporation | |||
(Registrant) | |||
Date: | February 7, 2019 | By: | /s/ Ted J. Jastrzebski |
Ted J. Jastrzebski | |||
Chief Financial Officer | |||
Date: | February 7, 2019 | By: | /s/ Ann P. Kelly |
Ann P. Kelly | |||
Vice President, Chief Accounting Officer | |||
and Corporate Controller | |||
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Exhibit 10.1
FORM OF CHANGE IN CONTROL AGREEMENT
This CHANGE IN CONTROL AGREEMENT ("Agreement") is made as of _____, between UGI Utilities, Inc. (the "Company") and _____ (the "Employee").
WHEREAS, the Company has determined that appropriate steps should be taken to reinforce and encourage the continued attention and dedication of key members of the Company's management to their assigned duties without distraction arising from the possibility of a Change in Control (as defined below), although no such change is now contemplated;
WHEREAS, in order to induce the Employee to remain in the employ of the Company, the Company agrees that the Employee shall receive the compensation set forth in this Agreement in the event the Employee's employment with the Company is terminated in connection with a Change in Control as a cushion against the financial and career impact on the Employee of any such Change in Control;
NOW, THEREFORE, in consideration of the foregoing and the mutual covenants and agreements hereinafter set forth and intending to be legally bound hereby, the parties hereby agree as follows:
1. Definitions. For all purposes of this Agreement, the following terms shall have the meanings specified in this Section unless the context clearly otherwise requires:
(a) "Affiliate" and "Associate" shall have the respective meanings ascribed to such terms in Rule 12b-2 of Regulation 12B under the Exchange Act and shall include, without
limitation, UGI Corporation and its subsidiaries.
(b) A Person shall be deemed the "Beneficial Owner" of any securities: (i) that such Person or any of such Person's Affiliates or Associates, directly or indirectly, has the right to acquire (whether such right is exercisable immediately or only after the passage of time) pursuant to any agreement, arrangement or understanding (whether or not in writing) or upon the exercise of conversion rights, exchange rights, rights, warrants or options, or otherwise; provided, however, that a Person shall not be deemed the "Beneficial Owner" of securities tendered pursuant to a tender or exchange offer made by such Person or any of such Person's Affiliates or Associates until such tendered securities are accepted for payment, purchase or exchange; (ii) that such Person or any of such Person's Affiliates or Associates, directly or indirectly, has the right to vote or dispose of or has "beneficial ownership" of (as determined pursuant to Rule 13d-3 of Regulation 13D-G under the Exchange Act), including without limitation pursuant to any agreement, arrangement or understanding, whether or not in writing; provided, however, that a Person shall not be deemed the "Beneficial Owner" of any security under this clause (ii) as a result of an oral or written agreement, arrangement or understanding to vote such security if such agreement, arrangement or understanding (A) arises solely from a revocable proxy given in response to a public proxy or consent solicitation made pursuant to, and
in accordance with, the applicable provisions of the Proxy Rules under the Exchange Act, and (B) is not then reportable by such Person on Schedule 13D under the Exchange Act (or any comparable or successor report); or (iii) that are beneficially owned, directly or indirectly, by any other Person (or any Affiliate or Associate thereof) with which such Person (or any of such Person's Affiliates or Associates) has any agreement, arrangement or understanding (whether or not in writing) for the purpose of acquiring, holding, voting (except pursuant to a revocable proxy as described in the proviso to clause (ii) above) or disposing of any voting securities of the Company; provided, however, that nothing in this Section 1(b) shall cause a Person engaged in business as an underwriter of securities to be the "Beneficial Owner" of any securities acquired through such Person's participation in good faith in a firm commitment underwriting until the expiration of 40 days after the date of such acquisition.
(c) "Board" shall mean the Board of Directors of the Company.
(d) "Cause" shall mean (i) misappropriation of funds, (ii) habitual insobriety or substance abuse, (iii) conviction of a crime involving moral turpitude, or (iv) gross negligence in the performance of duties, which gross negligence has had a material adverse effect on the business, operations, assets, properties or financial condition of the Company. The determination of Cause shall be made by an affirmative vote of at least two-thirds of the members of the Board at a duly called meeting of the Board.
(e) "Change in Control" shall have the meaning set forth in the attached Exhibit A to this Agreement.
(f) "COBRA Cost" shall mean 100% of the "applicable premium" under section 4980B(f)(4) of the Code for continued medical and dental COBRA Coverage under the
Company's benefit plans.
(g) "COBRA Coverage" shall mean continued medical and dental coverage under the Company's benefit plans, as determined under section 4980B of the Code.
(h) "Code" shall mean the Internal Revenue Code of 1986, as amended.
(i) "Compensation Committee" shall mean the Compensation and Management Development Committee of the Board.
(j) "Continuation Period" shall mean the ___-year period beginning on the Employee's Termination Date.
(h) "Exchange Act" shall mean the Securities Exchange Act of 1934, as amended.
(i) "Executive Severance Plan" shall mean the Company's Senior Executive Employee Severance Pay Plan, as in effect from time to time.
(j) "Good Reason Termination" shall mean a Termination of Employment initiated by the Employee upon one or more of the following occurrences:
(i) a material breach by the Company of any terms of this Agreement, including without limitation a material breach of Section 2 or 13 of this Agreement;
(ii) a material diminution in the authority, duties or responsibilities held by the Employee immediately prior to the Change in Control;
(iii) a material diminution in the Employee's base compensation as in effect immediately prior to the Change in Control; or
(iv) a material change in the geographic location at which the Employee must perform services (which, for purposes of this Agreement, means the Employee is required to report, other than on a temporary basis (less than 12 months), to a location which is more than 50 miles from the Employee's principal place of business immediately preceding the Change in Control, without the Employee's express written consent).
Notwithstanding the foregoing, the Employee shall be considered to have a Good Reason Termination only if the Employee provides written notice to the Company, pursuant to Section 3, specifying in reasonable detail the events or conditions upon which the Employee is basing such Good Reason Termination and the Employee provides such notice within 90 days after the event that gives rise to the Good Reason Termination. Within 30 days after notice has been provided, the Company shall have the opportunity, but shall have no obligation, to cure such events or conditions that give rise to the Good Reason Termination. If the Company does not cure such events or conditions within the 30-day period, the Employee may terminate employment with the Company based on Good Reason Termination within 30 days after the expiration of the cure period.
(n) "Key Employee" shall mean an employee who, at any time during the 12-month period ending on the identification date, is a "specified employee" under section 409A of the Code, as determined by the Compensation Committee or its delegate. The determination of Key Employees, including the number and identity of persons considered specified employees and the identification date, shall be made by the Compensation Committee or its delegate in accordance with the provisions of section 409A of the Code and the regulations issued thereunder.
(o) "Postponement Period" shall mean, for a Key Employee, the period of six months after separation from service (or such other period as may be required by section 409A of the Code), during which severance payments may not be paid to the Key Employee under section 409A of the Code.
(p) "Release" shall mean a release of any and all claims against the Company, its Affiliates, its Subsidiaries and all related parties with respect to all matters arising out of the Employee's employment by the Company and its Affiliates and Subsidiaries, or the termination
thereof (other than claims relating to amounts payable under this Agreement or benefits accrued under any plan, program or arrangement of the Company or any of its Subsidiaries or Affiliates) and shall be in the form required by the Company of its terminating executives immediately prior to the Change in Control.
(q) "Subsidiary" shall mean any corporation in which the Company, directly or indirectly, owns at least a 50% interest or an unincorporated entity of which the Company, directly or indirectly, owns at least 50% of the profits or capital interests.
(r) "Termination Date" shall mean the effective date of the Employee's Termination of Employment, as specified in the Notice of Termination.
(s) "Termination of Employment" shall mean the termination of the Employee's actual employment relationship with the Company and its Subsidiaries and Affiliates.
2. Employment. After a Change in Control, during the term of the Agreement, Employee shall continue to serve in the same or a comparable executive position with the Company as in effect immediately before the Change in Control, and with the same or a greater target level of annual and long-term compensation as in effect immediately before the Change in Control.
3. Notice of Termination. Any Termination of Employment upon or following a Change in Control shall be communicated by a Notice of Termination to the other party hereto given in accordance with Section 14 hereof. For purposes of this Agreement, a "Notice of Termination" means a written notice which (i) indicates the specific provision in this Agreement relied upon, (ii) briefly summarizes the facts and circumstances deemed to provide a basis for the Employee's Termination of Employment under the provision so indicated, and (iii) if the Termination Date is other than the date of receipt of such notice, specifies the Termination Date (which date shall not be more than 15 days after the giving of such notice) except as provided in Section 1(m) above.
4. Severance Compensation upon Termination of Employment.
(a) In the event of the Employee's involuntary Termination of Employment by the Company or a Subsidiary or Affiliate for any reason other than Cause or in the event of a Good Reason Termination, in either event upon or within two years after a Change in Control, the Employee will receive the following amounts in lieu of any severance compensation and benefits under the Executive Severance Plan or any other severance plan of the Company or a Subsidiary or Affiliate:
(i) The Company shall pay to the Employee a lump sum cash payment equal to the greater of (A) or (B) as set forth below:
(A) The Separation Pay and Paid Notice as calculated under the terms of the Executive Severance Plan based on the Employee's compensation and service as of the Termination Date, or
(B) ____ multiplied by the sum of (1) the Employee's annual base salary plus (2) the Employee's annual bonus. The annual base salary for this purpose shall be the Employee's annual base salary in effect as of the Employee's Termination Date. The annual bonus shall be calculated for this purpose as the greater of (x) the average annual cash bonus paid to the Employee for the three full fiscal years of the Company preceding the fiscal year in which the Termination Date occurs or (y) the Employee's target annual cash bonus for the fiscal year in which the Termination Date occurs. For purposes of the preceding sentence, if the Employee has not received an annual cash bonus for three full fiscal years, the Employee's average annual cash bonus shall be determined by dividing the total annual cash bonuses received by the Employee during the preceding three full fiscal years by the number of full and fractional years for which the Employee received an annual cash bonus during such three-year period.
(ii) The Company shall pay to the Employee a single lump sum payment equal to the COBRA Cost that the Employee would incur if the Employee continued medical and dental coverage under the Company's benefit plans during the Continuation Period, based on the benefits in effect for the Employee (and, if applicable, his or her spouse and dependents) at the Termination Date, less the amount that the Employee would be required to contribute for medical and dental coverage if the Employee were an active employee. The cash payment shall include a tax gross up payment equal to 75% of the lump sum amount described in the preceding sentence. The Employee may elect continuation coverage under the Company's applicable medical and dental plans during the Continuation Period by paying the COBRA Cost of such coverage. COBRA Coverage shall run concurrently with the Continuation Period, and nothing in this Section shall limit the Employee's right to elect COBRA Coverage for the full period permitted by law.
(iii) The Employee's benefit under the Company's executive retirement plan in which the Employee participates shall be calculated as if the Employee had continued in employment during the Continuation Period, earning base salary and bonus at the annual rate calculated under subsection (i)(B) above.
(iv) The Company shall pay to the Employee an amount equal to the Employee's target annual cash bonus amount for the Company's fiscal year in which the Termination Date occurs, multiplied by the number of months (with a partial month counting as a full month) elapsed in the fiscal year to the Termination Date and divided by 12, as well as any amounts due but not yet paid from the prior year under such plan.
(b) Notwithstanding the foregoing, no payments shall be made to the Employee under this Section 4 unless the Employee signs and does not revoke a Release. The amounts described in subsections (a) (i), (ii) and (iv) above shall be paid on the 30th day after the Termination Date subject to the Company's receipt of a Release and expiration of the revocation
period for the Release. Payments under this Agreement shall be made by mail to the last address provided for notices to the Employee pursuant to Section 14 of this Agreement.
5. Other Payments.
Upon any Termination of Employment entitling the Employee to payments under this Agreement, the Employee shall receive all accrued but unpaid salary and all benefits accrued and payable under any plans, policies and programs of the Company and its Subsidiaries or Affiliates, provided that the Employee shall not receive severance benefits under the Executive Severance Plan or any other severance plan of the Company or a Subsidiary or Affiliate.
6. Interest; Enforcement.
(a) If the Company shall fail or refuse to pay any amounts due the Employee under Section 4 on the applicable due date, the Company shall pay interest at the rate described below on the unpaid payments from the applicable due date to the date on which such amounts are paid. Interest shall be credited at an annual rate equal to the rate listed in the Wall Street Journal as the "prime rate" as of the Employee's Termination Date, plus 1%, compounded annually.
(b) It is the intent of the parties that the Employee not be required to incur any expenses associated with the enforcement of the Employee's rights under this Agreement by arbitration, litigation or other legal action, because the cost and expense thereof would substantially detract from the benefits intended to be extended to the Employee hereunder. Accordingly, the Company shall pay the Employee on demand the amount necessary to reimburse the Employee in full for all reasonable expenses (including all attorneys' fees and legal expenses) incurred by the Employee in enforcing any of the obligations of the Company under this Agreement. The Employee shall notify the Company of the expenses for which the Employee demands reimbursement within 60 days after the Employee receives an invoice for such expenses, and the Company shall pay the reimbursement amount within 15 days after receipt of such notice.
7. No Mitigation. The Employee shall not be required to mitigate the amount of any payment or benefit provided for in this Agreement by seeking other employment or otherwise, nor shall the amount of any payment or benefit provided for herein be reduced by any compensation earned by other employment or otherwise.
8. Non-Exclusivity of Rights. Nothing in this Agreement shall prevent or limit the Employee's continuing or future participation in or rights under any benefit, bonus, incentive or other plan or program provided by the Company, or any of its Subsidiaries or Affiliates, and for which the Employee may qualify.
9. No Set-Off. The Company's obligation to make the payments provided for in this Agreement and otherwise to perform its obligations hereunder shall not be affected by any
circumstances, including, without limitation, any set-off, counterclaim, recoupment, defense or other right which the Company may have against the Employee or others.
10. Taxation. All payments under this Agreement shall be subject to all requirements of the law with regard to tax withholding and reporting and filing requirements, and the Company shall use its best efforts to satisfy promptly all such requirements.
11. Effect of Section 280G on Payments.
(a) Notwithstanding any other provisions of this Agreement to the contrary, in the event that it shall be determined that any payment or distribution in the nature of compensation (within the meaning of section 280G(b)(2) of the Code) to or for the benefit of the Employee, whether paid or payable or distributed or distributable pursuant to the terms of this Agreement or otherwise (the "Payments"), would constitute an "excess parachute payment" within the meaning of section 280G of the Code, the Company shall reduce (but not below zero) the aggregate present value of the Payments under the Agreement to the Reduced Amount (as defined below), if reducing the Payments under this Agreement will provide the Employee with a greater net after-tax amount than would be the case if no reduction was made. The Payments shall be reduced as described in the preceding sentence only if (A) the net amount of the Payments, as so reduced (and after subtracting the net amount of federal, state and local and payroll income taxes on the reduced Payments), is greater than or equal to (B) the net amount of the Payments without such reduction (but after subtracting the net amount of federal, state and local and payroll income taxes on the Payments and the amount of Excise Tax (as defined below) to which the Employee would be subject with respect to the unreduced Payments). Only amounts payable under this Agreement shall be reduced pursuant to this subsection (a). The "Reduced Amount" shall be an amount expressed in present value that maximizes the aggregate present value of Payments under this Agreement without causing any Payment under this Agreement to be subject to the Excise Tax, determined in accordance with section 280G(d)(4) of the Code. The term "Excise Tax" means the excise tax imposed under section 4999 of the Code, together with any interest or penalties imposed with respect to such excise tax.
(b) All determinations to be made under this Section 11 shall be made by an independent registered public accounting firm or consulting firm selected by the Company immediately prior to the Change in Control, which shall provide its determinations and any supporting calculations both to the Company and the Employee within 10 days of the Change in Control. Any such determination by such firm shall be binding upon the Company and the Employee.
(c) All of the fees and expenses of the firm in performing the determinations referred to in this Section shall be borne solely by the Company.
12. Term of Agreement. The term of this Agreement shall be for three years from the date hereof and shall be automatically renewed for successive one-year periods unless the Company notifies the Employee in writing that this Agreement will not be renewed at least 60 days prior to the end of the then current term; provided, however, that (i) if a Change in Control
occurs during the term of this Agreement, this Agreement shall remain in effect for two years following such Change in Control or until all of the obligations of the parties hereunder are satisfied or have expired, if later, and (ii) this Agreement shall terminate if the Employee's employment with the Company terminates for any reason before a Change in Control (regardless of whether the Employee is thereafter employed by a Subsidiary or Affiliate of the Company).
13. Successor Company. The Company shall require any successor or successors (whether direct or indirect, by purchase, merger or otherwise) to all or substantially all of the business or assets of the Company, by agreement in form and substance satisfactory to the Employee, to acknowledge expressly that this Agreement is binding upon and enforceable against the Company in accordance with the terms hereof, and to become jointly and severally obligated with the Company to perform this Agreement in the same manner and to the same extent that the Company would be required to perform if no such succession or successions had taken place. Failure of the Company to notify the Employee in writing as to such successorship, to provide the Employee the opportunity to review and agree to the successor's assumption of this Agreement or to obtain such agreement prior to the effectiveness of any such succession shall be a breach of this Agreement. As used in this Agreement, the Company shall mean the Company as defined above and any such successor or successors to its business or assets, jointly and severally.
14. Notice. All notices and other communications required or permitted hereunder or necessary or convenient in connection herewith shall be in writing and shall be delivered personally or mailed by registered or certified mail, return receipt requested, or by overnight express courier service, as follows:
If to the Company, to:
460 North Gulph Road
King of Prussia, PA 19406
Attention: Corporate Secretary
If to the Employee, to the most recent address provided by the Employee to the Company or a Subsidiary or Affiliate for payroll purposes,
or to such other address as the Company or the Employee, as the case may be, shall designate by notice to the other party hereto in the manner specified in this Section; provided, however, that if no such notice is given by the Company following a Change in Control, notice at the last address of the Company or any successor pursuant to Section 13 shall be deemed sufficient for the purposes hereof. Any such notice shall be deemed delivered and effective when received in the case of personal delivery, five days after deposit, postage prepaid, with the U.S. Postal Service in the case of registered or certified mail, or on the next business day in the case of overnight express courier service.
15. Section 409A of the Code.
(a) This Agreement is intended to meet the requirements of the "short-term deferral exception," "separation pay exception" and other exceptions under section 409A of the Code, as applicable. However, if the Employee is a Key Employee and if required by section 409A of the Code, no payments or benefits under this Agreement shall be paid to the Employee during the Postponement Period. If payment is required to be delayed for the Postponement Period pursuant to section 409A, the accumulated amounts withheld on account of section 409A, with interest as described in Section 6 above, shall be paid in a lump sum payment within 15 days after the end of the Postponement Period. If the Employee dies during the Postponement Period prior to the payment of benefits, the amounts withheld on account of section 409A, with interest as described above, shall be paid to the Employee's estate within 60 days after the Employee's death.
(b) Notwithstanding anything in this Agreement to the contrary, if required by section 409A, payments may only be made under this Agreement upon an event and in a manner permitted by section 409A, to the extent applicable. As used in the Agreement, the term "termination of employment" shall mean the Employee's separation from service with the Company and its Subsidiaries and Affiliates within the meaning of section 409A and the regulations promulgated thereunder. For purposes of section 409A, each payment under the Agreement shall be treated as a separate payment. In no event may the Employee designate the year of payment for any amounts payable under the Agreement. All reimbursements and in-kind benefits provided under the Agreement shall be made or provided in accordance with the requirements of section 409A of the Code.
16. Governing Law. This Agreement shall be governed by and interpreted under the laws of the Commonwealth of Pennsylvania without giving effect to any conflict of laws provisions.
17. Contents of Agreement; Amendment. This Agreement supersedes all prior agreements with respect to the subject matter hereof (including without limitation any other change in control agreement in effect between the Company or a Subsidiary or Affiliate and the Employee) and sets forth the entire understanding between the parties hereto with respect to the subject matter hereof. This Agreement cannot be amended except pursuant to approval by the Board and a written amendment executed by the Employee and the Chair of the Compensation Committee. The provisions of this Agreement may require a variance from the terms and conditions of certain compensation or bonus plans under circumstances where such plans would not provide for payment thereof in order to obtain the maximum benefits for the Employee. It is the specific intention of the parties that the provisions of this Agreement shall supersede any provisions to the contrary in such plans, and such plans shall be deemed to have been amended to correspond with this Agreement without further action by the Company or the Board.
18. No Right to Continued Employment. Nothing in this Agreement shall be construed as giving the Employee any right to be retained in the employ of the Company or a Subsidiary or Affiliate.
19. Successors and Assigns. All of the terms and provisions of this Agreement shall be binding upon and inure to the benefit of and be enforceable by the respective heirs, representatives, successors and assigns of the parties hereto, except that the duties and responsibilities of the Employee and the Company hereunder shall not be assignable in whole or in part.
20. Severability. If any provision of this Agreement or application thereof to anyone or under any circumstances shall be determined to be invalid or unenforceable, such invalidity or unenforceability shall not affect any other provisions or applications of this Agreement which can be given effect without the invalid or unenforceable provision or application.
21. Remedies Cumulative; No Waiver. No right conferred upon the Employee by this Agreement is intended to be exclusive of any other right or remedy, and each and every such right or remedy shall be cumulative and shall be in addition to any other right or remedy given hereunder or now or hereafter existing at law or in equity. No delay or omission by the Employee in exercising any right, remedy or power hereunder or existing at law or in equity shall be construed as a waiver thereof.
22. Miscellaneous. All section headings are for convenience only. This Agreement may be executed in several counterparts, each of which is an original. It shall not be necessary in making proof of this Agreement or any counterpart hereof to produce or account for any of the other counterparts.
23. Arbitration. In the event of any dispute under the provisions of this Agreement other than a dispute in which the sole relief sought is an equitable remedy such as an injunction, the parties shall be required to have the dispute, controversy or claim settled by arbitration in Montgomery County, Pennsylvania, in accordance with the commercial arbitration rules then in effect of the American Arbitration Association, before one arbitrator who shall be an executive officer or former executive officer of a publicly traded corporation, selected by the parties. Any award entered by the arbitrator shall be final, binding and nonappealable and judgment may be entered thereon by either party in accordance with applicable law in any court of competent jurisdiction. This arbitration provision shall be specifically enforceable. The arbitrator shall have no authority to modify any provision of this Agreement or to award a remedy for a dispute involving this Agreement other than a benefit specifically provided under or by virtue of the Agreement. The Company shall be responsible for all of the fees of the American Arbitration Association and the arbitrator and any expenses relating to the conduct of the arbitration (including reasonable attorneys' fees and expenses).
IN WITNESS WHEREOF, the undersigned, intending to be legally bound, have executed this Agreement as of the date first written above. By executing this Agreement, the undersigned acknowledge that this Agreement replaces and supersedes any other understanding regarding the matters described herein.
UGI Utilities, Inc.
By: _______________________
___________________________
EXHIBIT A
UGI UTILITIES, INC.
CHANGE IN CONTROL
For purposes of this Agreement, "Change in Control" shall mean:
(i) Any Person (except the Employee, his Affiliates and Associates, UGI Corporation ("UGI"). any Subsidiary of UGI, any employee benefit plan of UGI or of any Subsidiary of UGI, or any Person or entity organized, appointed or established by UGI or any Subsidiary of UGI for or pursuant to the terms of any such employee benefit plan), together with all Affiliates and Associates of such Person, becomes the Beneficial Owner in the aggregate of 20% or more of either (i) the then outstanding shares of common stock of UGI (the "Outstanding UGI Common Stock") or (ii) the combined voting power of the then outstanding voting securities of UGI entitled to vote generally in the election of directors (the "UGI Voting Securities"); or
(ii) Individuals who, as of the beginning of any 24-month period, constitute the UGI Board of Directors (the "Incumbent UGI Board") cease for any reason to constitute at least a majority of the Incumbent UGI Board, provided that any individual becoming a director of UGI subsequent to the beginning of such period whose election or nomination for election by the UGI stockholders was approved by a vote of at least a majority of the directors then comprising the Incumbent UGI Board shall be considered as though such individual were a member of the Incumbent UGI Board, but excluding, for this purpose, any such individual whose initial assumption of office is in connection with an actual or threatened election contest relating to the election of the Directors of UGI; or
(iii) Consummation by UGI of a reorganization, merger or consolidation (a "Business Combination"), in each case, with respect to which all or substantially all of the individuals and entities who were the respective Beneficial Owners of the Outstanding UGI Common Stock and UGI Voting Securities immediately prior to such Business Combination do not, following such Business Combination, Beneficially Own, directly or indirectly, more than 50% of, respectively, the then outstanding shares of common stock and the combined voting power of the then outstanding voting securities entitled to vote generally in the election of directors, as the case may be, of the corporation resulting from such Business Combination in substantially the same proportion as their ownership immediately prior to such Business Combination of the Outstanding UGI Common Stock and UGI Voting Securities, as the case may be;
(iv) (A) Consummation of a complete liquidation or dissolution of UGI or (B) sale or other disposition of all or substantially all of the assets of UGI other than to a corporation with respect to which, following such sale or disposition, more than 50% of, respectively, the then outstanding shares of common stock and the combined voting power of the then outstanding voting securities entitled to vote generally in the election of directors is then owned beneficially, directly or indirectly, by all or substantially all of the individuals and entities who were the Beneficial Owners, respectively, of the Outstanding UGI Common Stock and UGI Voting Securities immediately prior to such sale or disposition in substantially the same proportion as
their ownership of the Outstanding UGI Common Stock and UGI Voting Securities, as the case may be, immediately prior to such sale or disposition; or
(v) UGI and its Subsidiaries fail to own more than 50% of the then outstanding shares of common stock of the Company or more than 50% of the combined voting power of the then outstanding voting securities of the Company entitled to vote generally in the election of directors; or
(vi) Consummation by the Company of a reorganization, merger or consolidation (a "Business Combination"), in each case, with respect to which all or substantially all of the individuals and entities who were the respective Beneficial Owners of the Company's outstanding common stock and voting securities immediately prior to such Business Combination do not, following such Business Combination, Beneficially Own, directly or indirectly, more than 50% of, respectively, the then outstanding shares of common stock and the combined voting power of the then outstanding voting securities entitled to vote generally in the election of directors, as the case may be, of the corporation resulting from such Business Combination in substantially the same proportion as their ownership immediately prior to such Business Combination of the Company's outstanding common stock and voting securities, as the case may be; or
(vii) Consummation of a complete liquidation or dissolution of the Company or sale or other disposition of all or substantially all of the assets of the Company other than to a corporation with respect to which, following such sale or disposition, more than 50% of, respectively, the then outstanding shares of common stock and the combined voting power of the then outstanding voting securities entitled to vote generally in the election of directors is then owned beneficially, directly or indirectly, by all or substantially all of the individuals and entities who were the Beneficial Owners, respectively, of the Company's outstanding common stock and voting securities immediately prior to such sale or disposition in substantially the same proportion as their ownership of the Company's outstanding common stock and voting securities, as the case may be, immediately prior to such sale or disposition.
EXHIBIT 31.1
CERTIFICATION
I, John L. Walsh, certify that:
1. | I have reviewed this periodic report on Form 10-Q of UGI Corporation; |
2. | Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; |
3. | Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; |
4. | The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: |
(a) | Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; |
(b) | Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; |
(c) | Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and |
(d) | Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and |
5. | The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions): |
(a) | All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and |
(b) | Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting. |
Date: | February 7, 2019 | ||
/s/ John L. Walsh | |||
John L. Walsh President and Chief Executive Officer of UGI Corporation | |||
EXHIBIT 31.2
CERTIFICATION
I, Ted J. Jastrzebski, certify that:
1. | I have reviewed this periodic report on Form 10-Q of UGI Corporation; |
2. | Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; |
3. | Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; |
4. | The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: |
(a) | Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; |
(b) | Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; |
(c) | Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and |
(d) | Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and |
5. | The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions): |
(a) | All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and |
(b) | Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting. |
Date: | February 7, 2019 | ||
/s/ Ted J. Jastrzebski | |||
Ted J. Jastrzebski | |||
Chief Financial Officer of UGI Corporation | |||
EXHIBIT 32
Certification by the Chief Executive Officer and Chief Financial Officer
Relating to a Periodic Report Containing Financial Statements
I, John L. Walsh, Chief Executive Officer, and I, Ted J. Jastrzebski, Chief Financial Officer, of UGI Corporation, a Pennsylvania corporation (the “Company”), hereby certify that to our knowledge:
(1) | The Company’s periodic report on Form 10-Q for the period ended December 31, 2018 (the “Form 10-Q”) fully complies with the requirements of Section 13(a) of the Securities Exchange Act of 1934, as amended; and |
(2) | The information contained in the Form 10-Q fairly presents, in all material respects, the financial condition and results of operations of the Company. |
CHIEF EXECUTIVE OFFICER | CHIEF FINANCIAL OFFICER | |||
/s/ John L. Walsh | /s/ Ted J. Jastrzebski | |||
John L. Walsh | Ted J. Jastrzebski | |||
Date: | February 7, 2019 | Date: | February 7, 2019 | |